Methods using well drilling fluids having clay control properties

ABSTRACT

Clay is stabilized in methods for drilling of wells and other formation treatment for hydrocarbon production by the addition to the drilling or other fluid including a choline compound together with an formation control additive.

RELATED APPLICATIONS

This application is a divisional application and claims the benefit ofand priority to U.S. patent application Ser. No. 11/328,432 filed 9 Jan.2006 (Jan. 9, 2006), now U.S. Pat. No. 8,097,567 issued 17 Jan. 2012(Jan. 17, 2012).

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to drilling of wells in the production ofoil, gas and other fluids from underground formations using a drillingfluid that reduces or prevents shale and/or clay swelling caused by theabsorption of water from drilling fluids during drilling, completionand/or production.

More particularly, the present invention relates to drilling of wells inthe production of oil, gas and other fluids from underground formationsusing a drilling fluid including a shale and/or clay treatmentcomposition including a choline compound and an amine or quaternaryammonium clay control compound, where the composition is pre-formed orgenerated in situ and where the compositions stabilizes boreholes and/orreduces or prevents shale and/or clay swelling caused by the absorptionof water from drilling fluids during drilling, completion and/orproduction.

2. Description of the Related Art

During drilling and/or completion, zones that comprise shales and/orreactive clays can become unstable, when they are in contact with waterin a drilling fluid. These zones contain clays that have been dehydratedover geologic time by overburden pressure. When these zone are exposedto a water containing material such as a drilling fluid, the claysosmotically imbibe water from the drilling fluid and swell. The swellingof the shale induces stresses, loss of mechanical strength, and shalefailure. See Thomas W. Beihoffer et al in the May 16, 1992 Oil & GasJournal, page 47 et seq., entitled “Cationic Polymer Drilling Fluid CanSometimes Replace Oil-based Mud” for a more in depth explanation of theproblem of drilling through clay containing zones. Shale crumbling intothe borehole (“sloughing”) can ultimately place a burden on the drillbit which makes it impossible to retrieve.

Salts such as potassium chloride have been widely used in drillingtreatments to convert the formation material from the sodium form by ionexchange to, for example, the potassium form which is less vulnerable toswelling; also the use of high concentrations of potassium salts affectsthe osmotic balance and tends to inhibit the flow of water away from thehigh potassium salt concentration fluids into the shale. However, it isdifficult to maintain the required high concentrations of potassiumsalts in the drilling fluids. In addition, the physical introduction ofsuch salts causes difficulties with the use of the viscosifyingmaterials typically used for drilling. Inorganic salts can also have aharmful effect on the environment if released.

There are three general types of amine and/or quaternary ammonium cationsources which have been suggested for clay treatment in during drillingoperations and hydrocarbon recovery. The three types include: (a)compounds having a single-site quaternary ammonium cation and amine, (b)compounds having a few (two to about six) amine or quaternary ammoniumcation sites, sometimes referred herein as “oligo-cationics”, and (c)quaternary ammonium or amine polymers, which may have from about six tothousands of cationic sites. Such prior art clay control compounds aredisclosed in U.S. Pat. Nos. 2,761,835; 2,761,840; 2,761,836; 4,842,073;U.S. Pat. Nos. 5,211,239; 2,761,843; 3,349,032; 4,447,342; 4,374,739;4,366,071 and 6,921,742, incorporated herein by reference.

Although there are numerous examples of drilling fluids having claycontrol additives, there is still a need in the art for drilling fluidshaving new clay control additives.

SUMMARY OF THE INVENTION

The present invention provides a method for controlling clay swelling indownhole operations including the step of supplying a downhole fluidincluding a base fluid and a clay control composition during drilling,fracturing, completion or production operations. The clay controlcomposition includes a choline compound and a quaternary ammonium oramine clay control compound. The fluid is then pumped downhole during adownhole operation in which a downhole zone including a swellable clayis in contact with the drilling fluid, where the clay controlcomposition reduces or prevents clay swelling while the clay is incontact with the drilling fluid.

The present invention also provides a method for drilling including thestep of supplying a drilling fluid including a clay control composition.The clay control composition includes a choline compound and aquaternary ammonium or amine clay control compound. The fluid is thenpumped downhole during drilling, when drilling into and through adownhole zone including a swellable clay, where the clay controlcomposition reduces or prevents clay swelling while the clay is incontact with the drilling fluid. The method can include the step ofchanging the drilling fluid or the drilling fluid additives prior to orafter drilling into and through the downhole zones including swellableclays.

The present invention provides a method for controlling clay swellingincluding the step of circulating a fluid into an oil or gas well havingexposed downhole zones including swellable clay, where the fluidincludes a clay control composition. The clay control compositionincludes a choline compound and a quaternary ammonium or amine claycontrol compound.

The present invention provides a shale and/or clay anti-swellingadditive for aqueous-based, drilling fluids, fracturing fluids,completion fluids and production fluids including a choline compound anda quaternary ammonium or amine clay control compound.

The present invention also provides a clay control composition includinga choline compound and a quaternary ammonium or amine clay controlcompound.

The present invention also provides for the use of a drilling fluidincluding a clay control composition, which includes a choline compoundand a quaternary ammonium or amine clay control compound, where the claycontrol composition reduces or prevent clay swelling when the fluid isin contact with a downhole zone containing swellable clay.

The present invention provides a method for fracturing a formationincluding the step of injecting an aqueous-based, fracturing fluid intoa formation, where the fluid includes an effective amount of a cholinesalt sufficient to facilitate formation fracturing and to reduce aswelling tendency of reactive shale and/or clay during fracturingoperations.

The present invention also provides a method for completing a wellincluding the steps of circulating an aqueous-based, completion fluid inthe well, where the fluid includes an effective amount of a cholinecarboxylate sufficient to reduce a swelling tendency of reactive shaleand/or clay during completion operations.

The present invention also provides a method for production of a wellincluding the steps of injecting an aqueous-based, production fluid intoa well to aid in oil and/or gas production, where the fluid includes aneffective amount of a choline carboxylate sufficient to reduce aswelling tendency of reactive shale and/or clay during completionoperations.

The present invention also provides a general purpose fluid for use inoil and gas drilling, production, fracturing and completion operations,where the fluid is substantially clear or includes substantially nosolids or solid forming ingredients and includes a choline salt, afoaming agent or weight reduction agent, a corrosion inhibitor andwater. The choline salt is present in an amount sufficient to reducereactive clay and/or shale swelling. The foaming agent is present in anamount sufficient to reduce the fluid weight when the fluid is mixedwith a gas to form a foam. The corrosion inhibitor is present in anamount sufficient to reduce corrosion of downhole components and thecholine salt does not adversely affect the corrosion inhibitingproperties of the corrosion inhibitor.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention can be better understood with reference to the followingillustrative drawings,

FIG. 1 depicts a plot of Zeta Potential Distrbution,

FIG. 2 depicts a plot of viscosity versus time for two fluids of theinvention.

DEFINITIONS OF THE INVENTION

An under-balanced and/or managed pressure drilling fluid means adrilling fluid having a hydrostatic density (pressure) lower or equal toa formation density (pressure). For example, if a known formation at10,000 ft (True Vertical Depth—TVD) has a hydrostatic pressure of 5,000psi or 9.6 lbm/gal, an under-balanced drilling fluid would have ahydrostatic pressure less than or equal to 9.6 lbm/gal. Mostunder-balanced and/or managed pressure drilling fluids include at leasta density reduction additive. Other additive many include a corrosioninhibitor, a pH modifier and a shale inhibitor.

The following definitions are provided in order to aid those skilled inthe art in understanding the detailed description of the presentinvention.

The term “amphoteric” refers to surfactants that have both positive andnegative charges. The net charge of the surfactant can be positive,negative, or neutral, depending on the pH of the solution.

The term “anionic” refers to those viscoelastic surfactants that possessa net negative charge.

The term “fracturing” refers to the process and methods of breaking downa geological formation, i.e. the rock formation around a well bore, bypumping fluid at very high pressures, in order to increase productionrates from a hydrocarbon reservoir. The fracturing methods of thisinvention use otherwise conventional techniques known in the art.

The term “proppant” refers to a granular substance suspended in thefracturing fluid during the fracturing operation, which serves to keepthe formation from closing back down upon itself once the pressure isreleased. Proppants envisioned by the present invention include, but arenot limited to, conventional proppants familiar to those skilled in theart such as sand, 20-40 mesh sand, resin-coated sand, sintered bauxite,glass beads, and similar materials.

The abbreviation “RPM” refers to relative permeability modifiers.

The term “surfactant” refers to a soluble, or partially soluble compoundthat reduces the surface tension of liquids, or reduces inter-facialtension between two liquids, or a liquid and a solid by congregating andorienting itself at these interfaces.

The term “viscoelastic” refers to those viscous fluids having elasticproperties, i.e., the liquid at least partially returns to its originalform when an applied stress is released.

The phrase “viscoelastic surfactants” or “VES” refers to that class ofcompounds which can form micelles (spherulitic, anisometric, lamellar,or liquid crystal) in the presence of counter ions in aqueous solutions,thereby imparting viscosity to the fluid. Anisometric micelles inparticular are preferred, as their behavior in solution most closelyresembles that of a polymer.

The abbreviation “VAS” refers to a Viscoelastic Anionic Surfactant,useful for fracturing operations and frac packing. As discussed herein,they have an anionic nature with preferred counterions of potassium,ammonium, sodium, calcium or magnesium.

DETAILED DESCRIPTION OF THE INVENTION

The inventors has found that shale and/or clay swelling and sloughingcan be controlled by adding a clay control composition including acholine compound and an amine or ammonium clay control compounds to adrilling fluid or other downhole fluid when the borehole passes throughdownhole zones including swellable clays. The inventor has found thatthe clay control composition of this invention can be added to anycirculating downhole fluid whenever the fluid comes in contact withdownhole zoned that include swellable clays. The use of the clay controlcomposition reduces or prevents clay swelling and the adverse effects ofclay or shale sloughing off into the well prior to cementing theborehole in the zones including the swellable clay. The clay controlcompositions of this invention are ideally suited for the treatment ofclay and shale in subterranean formations during drilling and otherwisefor the stabilization of clay and clay-containing shale.

The present invention broadly relates to a method for control clayswelling and sloughing including the step of adding a clay controlcomposition including a choline compound and an amine or ammonium claycontrol compound or mixtures and combinations thereof to fluid beingcirculated through an oil or gas well during drilling, completion,production, intervention, enhancing operations or any other operationwhere downhole zone containing swellable clay are brought in contactwith an aqueous or water-containing fluid.

Fracturing Fluids

Generally, a hydraulic fracturing treatment involves pumping aproppant-free viscous fluid, or pad, usually water with some fluidadditives to generate high viscosity, into a well faster than the fluidcan escape into the formation so that the pressure rises and the rockbreaks, creating artificial fracture and/or enlarging existing fracture.After fracturing the formation, a propping agent such as sand is addedto the fluid to form a slurry that is pumped into the newly formedfractures in the formation to prevent them from closing when the pumpingpressure is released. The proppant transport ability of a base fluiddepends on the type of viscosifying additives added to the water base.

Water-base fracturing fluids with water-soluble polymers added to make aviscosified solution are widely used in the art of fracturing. Since thelate 1950s, more than half of the fracturing treatments are conductedwith fluids comprising guar gums, high-molecular weight polysaccharidescomposed of mannose and galactose sugars, or guar derivatives such ashydropropyl guar (HPG), hydroxypropylcellulose (HPC), carboxymethyl guar(CMG). carboxymethylhydropropyl guar (CMHPG). Crosslinking agents basedon boron, titanium, zirconium or aluminum complexes are typically usedto increase the effective molecular weight of the polymer and make thembetter suited for use in high-temperature wells.

To a lesser extent, cellulose derivatives such as hydroxyethylcellulose(HEC) or hydroxypropylcellulose (HPC) andcarboxymethylhydroxyethylcellulose (CMHEC) are also used, with orwithout crosslinkers. Xanthan and scleroglucan, two biopolymers, havebeen shown to have excellent proppant-suspension ability even thoughthey are more expensive than guar derivatives and therefore used lessfrequently. Polyacrylamide and polyacrylate polymers and copolymers areused typically for high-temperature applications or friction reducers atlow concentrations for all temperatures ranges.

Polymer-free, water-base fracturing fluids can be obtained usingviscoelastic surfactants. These fluids are normally prepared by mixingin appropriate amounts of suitable surfactants such as anionic,cationic, nonionic and zwitterionic surfactants. The viscosity ofviscoelastic surfactant fluids is attributed to the three dimensionalstructure formed by the components in the fluids. When the concentrationof surfactants in a viscoelastic fluid significantly exceeds a criticalconcentration, and in most cases in the presence of an electrolyte,surfactant molecules aggregate into species such as micelles, which caninteract to form a network exhibiting viscous and elastic behavior.

Cationic viscoelastic surfactants—typically consisting of long-chainquaternary ammonium salts such as cetyltrimethylammonium bromide(CTAB)—have been so far of primarily commercial interest in wellborefluid. Common reagents that generate viscoelasticity in the surfactantsolutions are salts such as ammonium chloride, potassium chloride,sodium chloride, sodium salicylate and sodium isocyanate and non-ionicorganic molecules such as chloroform. The electrolyte content ofsurfactant solutions is also an important control on their viscoelasticbehavior. Reference is made for example to U.S. Pat. No. 4,695,389, U.S.Pat. No. 4,725,372, U.S. Pat. No. 5,551,516, U.S. Pat. No. 5,964,295,and U.S. Pat. No. 5,979,557, incorporated herein by reference. However,fluids comprising this type of cationic viscoelastic surfactants usuallytend to lose viscosity at high brine concentration (10 pounds per gallonor more). Therefore, these fluids have seen limited use asgravel-packing fluids or drilling fluids, or in other applicationsrequiring heavy fluids to balance well pressure. Anionic viscoelasticsurfactants are also used.

It is also known from International Patent Publication WO 98/56497, toimpart viscoelastic properties using amphoteric/zwitterionic surfactantsand an organic acid, salt and/or inorganic salt. The surfactants are forinstance dihydroxyl alkyl glycinate, alkyl ampho acetate or propionate,alkyl betaine, alkyl amidopropyl betaine and alkylamino mono- ordi-propionates derived from certain waxes, fats and oils. Thesurfactants are used in conjunction with an inorganic water-soluble saltor organic additives such as phthalic acid, salicylic acid or theirsalts. Amphoteric/zwitterionic surfactants, in particular thosecomprising a betaine moiety are useful at temperature up to about 150°C. and are therefore of particular interest for medium to hightemperature wells. However, like the cationic viscoelastic surfactantsmentioned above, they are usually not compatible with high brineconcentration.

According to a preferred embodiment of the invention, the treatmentconsists in alternating viscoelastic-base fluid stages (or a fluidhaving relatively poor proppant capacity, such as a polyacrylamide-basedfluid, in particular at low concentration) with stages having highpolymer concentrations. Preferably, the pumping rate is kept constantfor the different stages but the proppant-transport ability may be alsoimproved (or alternatively degraded) by reducing (or alternativelyincreasing) the pumping rate.

The proppant type can be sand, intermediate strength ceramic proppants(available from Carbo Ceramics, Norton Proppants, etc.), sinteredbauxites and other materials known to the industry. Any of these basepropping agents can further be coated with a resin (available fromSantrol, a Division of Fairmount Industries, Borden Chemical, etc.) topotentially improve the clustering ability of the proppant. In addition,the proppant can be coated with resin or a proppant flowback controlagent such as fibers for instance can be simultaneously pumped. Byselecting proppants having a contrast in one of such properties such asdensity, size and concentrations, different settling rates will beachieved.

“Waterfrac” treatments employ the use of low cost, low viscosity fluidsin order to stimulate very low permeability reservoirs. The results havebeen reported to be successful (measured productivity and economics) andrely on the mechanisms of asperity creation (rock spalling), sheardisplacement of rock and localized high concentration of proppant tocreate adequate conductivity. It is the last of the three mechanismsthat is mostly responsible for the conductivity obtained in “waterfrac”treatments. The mechanism can be described as analogous to a wedgesplitting wood.

Viscous well treatment fluids are commonly used in the drilling,completion, and treatment of subterranean formations penetrated bywellbores. A viscous well treatment fluid is generally composed of apolysaccharide or synthetic polymer in an aqueous solution which iscrosslinked by an organometallic compound. Examples of well treatmentsin which metal-crosslinked polymers are used are hydraulic fracturing,gravel packing operations, water blocking, and other well completionoperations.

Hydraulic fracturing techniques are widely employed to enhance oil andgas production from subterranean formations. During hydraulicfracturing, fluid is injected into a well bore under high pressure. Oncethe natural reservoir pressures are exceeded, the fracturing fluidinitiates a fracture in the formation which generally continues to growduring pumping. As the fracture widens to a suitable width during thecourse of the treatment, a propping agent is then also added to thefluid. The treatment design generally requires the fluid to reach amaximum viscosity as it enters the fracture which affects the fracturelength and width. The viscosity of most fracturing fluids is generatedfrom water-soluble polysaccharides, such as galactomannans or cellulosederivatives. Employing crosslinking agents, such as borate, titanate, orzirconium ions, can further increase the viscosity. The gelled fluid maybe accompanied by a propping agent (i.e., proppant) which results inplacement of the proppant within the fracture thus produced. Theproppant remains in the produced fracture to prevent the completeclosure of the fracture and to form a conductive channel extending fromthe well bore into the formation being treated once the fracturing fluidis recovered.

In order for the treatment to be successful, it is preferred that thefluid viscosity eventually diminish to levels approaching that of waterafter the proppant is placed. This allows a portion of the treatingfluid to be recovered without producing excessive amounts of proppantafter the well is opened and returned to production. The recovery of thefracturing fluid is accomplished by reducing the viscosity of the fluidto a lower value such that it flows naturally from the formation underthe influence of formation fluids. This viscosity reduction orconversion is referred to as “breaking” and can be accomplished byincorporating chemical agents, referred to as “breakers,” into theinitial gel.

Certain gels of fracturing fluids, such as those based upon guarpolymers, undergo a natural break without the intervention of a breakingagent. However, the breaking time for such gelled fluids generally isexcessive and impractical, being somewhere in the range from greaterthan 24 hours to in excess of weeks, months, or years depending onreservoir conditions. Accordingly, to decrease the break time of gelsused in fracturing, chemical agents are usually incorporated into thegel and become a part of the gel itself. Typically, these agents areeither oxidants or enzymes which operate to degrade the polymeric gelstructure. Most degradation or “breaking” is caused by oxidizing agents,such as persulfate salts (used either as is or encapsulated), chromoussalts, organic peroxides or alkaline earth or zinc peroxide salts, or byenzymes.

In addition to the importance of providing a breaking mechanism for thegelled fluid to facilitate recovery of the fluid and to resumeproduction, the timing of the break is also of great importance. Gelswhich break prematurely can cause suspended proppant material to settleout of the gel before being introduced a sufficient distance into theproduced fracture. Premature breaking can also lead to a prematurereduction in the fluid viscosity, resulting in a less than desirablefracture width in the formation causing excessive injection pressuresand premature termination of the treatment.

On the other hand, gelled fluids which break too slowly can cause slowrecovery of the fracturing fluid from the produced fracture withattendant delay in resuming the production of formation fluids andseverely impair anticipated hydrocarbon production. Additional problemsmay occur, such as the tendency of proppant to become dislodged from thefracture, resulting in at least partial closing and decreased efficiencyof the fracturing operation. Preferably, the fracturing gel should beginto break when the pumping operations are concluded. For practicalpurposes, the gel preferably should be completely broken within about 24hours after completion of the fracturing treatment. Gels useful in thisregard include those disclosed in U.S. Pat. Nos. 3,960,736; 5,224,546;6,756,345; and 6,793,018, incorporated herein by reference.

Fracturing fluid compositions of this invention comprise a solvent, apolymer soluble or hydratable in the solvent, a crosslinking agent, aninorganic breaking agent, an optional ester compound and a cholinecarboxylate. Preferably, the solvent includes water, and the polymer ishydratable in water. The solvent may be an aqueous potassium chloridesolution. The inorganic breaking agent may be a metal-based oxidizingagent, such as an alkaline earth metal or a transition metal. Theinorganic breaking agent may be magnesium peroxide, calcium peroxide, orzinc peroxide. The ester compound may be an ester of a polycarboxylicacid. For example, the ester compound may be an ester of oxalate,citrate, or ethylene diamine tetraacetate. The ester compound havinghydroxyl groups can also be acetylated. An example of this is thatcitric acid can be acetylated to form acetyl triethyl citrate. Apresently preferred ester is acetyl triethyl citrate. The hydratablepolymer may be a water soluble polysaccharide, such as galactomannan,cellulose, or derivatives thereof. The crosslinking agent may be aborate, titanate, or zirconium-containing compound. For example, thecrosslinking agent can be sodium boratexH₂O (varying waters ofhydration), boric acid, borate crosslinkers (a mixture of a titanateconstituent, preferably an organotitanate constituent, with a boronconstituent. The organotitanate constituent can be TYZOR® titaniumchelate esters from E.I du Pont de Nemours & Company. The organotitanateconstituent can be a mixture of a first organotitanate compound having alactate base and a second organotitanate compound having triethanolaminebase. The boron constituent can be selected from the group consisting ofboric acid, sodium tetraborate, and mixtures thereof. These aredescribed in U.S. Pat. No. 4,514,309, incorporated herein by reference,borate based ores such as ulexite and colemanite, Ti(IV)acetylacetonate, Ti(IV) triethanolamine, Zr lactate, Zr triethanolamine,Zr lactate-triethanolamine, or Zrlactate-triethanolamine-triisopropanolamine. In some embodiments, thewell treatment fluid composition may further comprise a proppant.

In another aspect, the invention relates to a well treatment fluidcomposition. The composition includes a solvent, a polymer soluble orhydratable in the solvent, a crosslinking agent, an alkaline earth metalor a transition metal-based breaking agent, an optional ester of acarboxylic acid and choline carboxylate. The breaking agent may bemagnesium peroxide, calcium peroxide, or zinc peroxide. The solvent mayinclude water, and the polymer is hydratable in water. The solvent maybe an aqueous potassium chloride solution. The hydratable polymer may bea polysaccharide.

In still another aspect, the invention relates to a method of treating asubterranean formation. The method comprises: formulating a fracturingfluid comprising a solvent, a polymer soluble or hydratable in thesolvent, a crosslinking agent, an inorganic breaking agent, a cholinecarboxylate and an optional ester compound; and injecting the fracturingfluid into a bore hole to contact at least a part of the formation bythe fracturing fluid under a sufficient pressure to fracture theformation. The fracturing fluid has a viscosity that changes in responseto a condition. The method may further comprise removing the fracturingfluid after the viscosity of the fracturing fluid is reduced. In someembodiments, the method may further comprise injecting a proppant intothe formation. The proppant may be injected into the formation with thefracturing fluid. The fracturing fluid may have a pH at or above about7. Preferably, the fracturing fluid should have a pH in the range ofabout 8 to about 12. The inorganic breaking agent may be a metal-basedoxidizing agent. The metal may be an alkaline earth metal or atransition metal. The inorganic breaking agent may be magnesiumperoxide, calcium peroxide, or zinc peroxide. The optional estercompound may be an ester of an polycarboxylic acid, such as an ester ofoxalate, citrate, or ethylene diamine tetraacetate. Preferably, thesolvent includes water, and the polymer is a water solublepolysaccharide, such as galactomannan, cellulose, or derivativesthereof. The solvent may be an aqueous potassium chloride solution. Thecrosslinking agent may be a borate, titanate, or zirconium-containingcompound. The fracturing fluid can further comprise sodium thiosulfate.

Embodiments of the invention provide a well treatment fluid compositionand a method of using the fluid composition to treat subterraneanformations. The well treatment fluid composition can be used inhydraulic fracturing as a fracturing fluid, gravel packing operations,water blocking, temporary plugs for purposes of wellbore isolationand/or fluid loss control and other well completion operations. Mostwell treatment fluids are aqueous, although non-aqueous fluids may beformulated and used as well.

The well treatment fluid composition comprises a solvent (such aswater), a polymer soluble or hydratable in the solvent, a crosslinkingagent, an inorganic breaking agent, a choline carboxylate of and anoptional ester compound. Optionally, the well treatment fluidcomposition may further include various other fluid additives, such aspH buffers, biocides, stabilizers, propping agents (i.e., proppants),mutual solvents, and surfactants designed to prevent emulsion withformation fluids, to reduce surface tension, to enhance load recovery,and/or to foam the fracturing fluid. The well treatment fluidcomposition may also contain one or more salts, such as potassiumchloride, magnesium chloride, sodium chloride, calcium chloride,tetramethyl ammonium chloride, and mixtures thereof. It is found that afracturing fluid made in accordance with embodiments of the inventionexhibits reduced or minimal premature breaking and breaks completely orsubstantially completely after a well treatment is finished.

“Premature breaking” as used herein refers to a phenomenon in which agel viscosity becomes diminished to an undesirable extent before all ofthe fluid is introduced into the formation to be fractured. Thus, to besatisfactory, the gel viscosity should preferably remain in the rangefrom about 50% to about 75% of the initial viscosity of the gel for atleast two hours of exposure to the expected operating temperature.Preferably the fluid should have a viscosity in excess of 100 centipoise(cP) at 100 sec⁻¹ while injection into the reservoir as measured on aFann 50 C viscometer in the laboratory.

“Complete breaking” as used herein refers to a phenomenon in which theviscosity of a gel is reduced to such a level that the gel can beflushed from the formation by the flowing formation fluids or that itcan be recovered by a swabbing operation. In laboratory settings, acompletely broken, non-crosslinked gel is one whose viscosity is about10 cP or less as measured on a Model 35 Fann viscometer having a R1B1rotor and bob assembly rotating at 300 rpm.

An aqueous fracturing fluid may be prepared by blending a hydratablepolymer with an aqueous base fluid. The base aqueous fluid can be, forexample, water or brine. Any suitable mixing apparatus may be used forthis procedure. In the case of batch mixing, the hydratable polymer andaqueous fluid are blended for a period of time which is sufficient toform a hydrated sol.

Suitable hydratable polymers that may be used in embodiments of theinvention include any of the hydratable polysaccharides which arecapable of forming a gel in the presence of a crosslinking agent. Forinstance, suitable hydratable polysaccharides include, but are notlimited to, galactomannan gums, glucomannan gums, guars, derived guars,and cellulose derivatives. Specific examples are guar gum, guar gumderivatives, locust bean gum, Karaya gum, carboxymethyl cellulose,carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose.Presently preferred gelling agents include, but are not limited to, guargums, hydroxypropyl guar, carboxymethyl hydroxypropyl guar,carboxymethyl guar, and carboxymethyl hydroxyethyl cellulose. Suitablehydratable polymers may also include synthetic polymers, such aspolyvinyl alcohol, polyacrylamides, poly-2-amino-2-methyl propanesulfonic acid, and various other synthetic polymers and copolymers.Other suitable polymers are known to those skilled in the art.

The hydratable polymer may be present in the fluid in concentrationsranging from about 0.10% to about 5.0% by weight of the aqueous fluid. Apreferred range for the hydratable polymer is about 0.20% to about 0.80%by weight.

A suitable crosslinking agent can be any compound that increases theviscosity of the fluid by chemical crosslinking, physical crosslinking,or any other mechanisms. For example, the gellation of a hydratablepolymer can be achieved by crosslinking the polymer with metal ionsincluding boron, zirconium, and titanium containing compounds, ormixtures thereof. One class of suitable crosslinking agents isorganotitanates. Another class of suitable crosslinking agents isborates as described, for example, in U.S. Pat. No. 4,514,309,incorporated herein by reference. The selection of an appropriatecrosslinking agent depends upon the type of treatment to be performedand the hydratable polymer to be used. The amount of the crosslinkingagent used also depends upon the well conditions and the type oftreatment to be effected, but is generally in the range of from about 10ppm to about 1000 ppm of metal ion of the crosslinking agent in thehydratable polymer fluid. In some applications, the aqueous polymersolution is crosslinked immediately upon addition of the crosslinkingagent to form a highly viscous gel. In other applications, the reactionof the crosslinking agent can be retarded so that viscous gel formationdoes not occur until the desired time.

The pH of an aqueous fluid which contains a hydratable polymer can beadjusted if necessary to render the fluid compatible with a crosslinkingagent. Preferably, a pH adjusting material is added to the aqueous fluidafter the addition of the polymer to the aqueous fluid. Typicalmaterials for adjusting the pH are commonly used acids, acid buffers,and mixtures of acids and bases. For example, sodium bicarbonate,potassium carbonate, sodium hydroxide, potassium hydroxide, and sodiumcarbonate are typical pH adjusting agents. Acceptable pH values for thefluid may range from neutral to basic, i.e., from about 5 to about 14.Preferably, the pH is kept neutral or basic, i.e., from about 7 to about14, more preferably between about 8 to about 12.

The term “breaking agent” or “breaker” refers to any chemical that iscapable of reducing the viscosity of a gelled fluid. As described above,after a fracturing fluid is formed and pumped into a subterraneanformation, it is generally desirable to convert the highly viscous gelto a lower viscosity fluid. This allows the fluid to be easily andeffectively removed from the formation and to allow desired material,such as oil or gas, to flow into the well bore. This reduction inviscosity of the treating fluid is commonly referred to as “breaking”Consequently, the chemicals used to break the viscosity of the fluid isreferred to as a breaking agent or a breaker.

There are various methods available for breaking a fracturing fluid or atreating fluid. Typically, fluids break after the passage of time and/orprolonged exposure to high temperatures. However, it is desirable to beable to predict and control the breaking within relatively narrowlimits. Mild oxidizing agents are useful as breakers when a fluid isused in a relatively high temperature formation, although formationtemperatures of 300° F. (149° C.) or higher will generally break thefluid relatively quickly without the aid of an oxidizing agent.

Examples of inorganic breaking agents for use in this invention include,but are not limited to, persulfates, percarbonates, perborates,peroxides, perphosphates, permanganates, etc. Specific examples ofinorganic breaking agents include, but are not limited to, alkalineearth metal persulfates, alkaline earth metal percarbonates, alkalineearth metal perborates, alkaline earth metal peroxides, alkaline earthmetal perphosphates, zinc salts of peroxide, perphosphate, perborate,and percarbonate, and so on. Additional suitable breaking agents aredisclosed in U.S. Pat. Nos. 5,877,127; 5,649,596; 5,669,447; 5,624,886;5,106,518; 6,162,766; and 5,807,812, incorporated herein by reference.In some embodiments, an inorganic breaking agent is selected fromalkaline earth metal or transition metal-based oxidizing agents, such asmagnesium peroxides, zinc peroxides, and calcium peroxides.

In addition, enzymatic breakers may also be used in place of or inaddition to a non-enzymatic breaker. Examples of suitable enzymaticbreakers such as guar specific enzymes, alpha and beta amylases,amyloglucosidase, aligoglucosidase, invertase, maltase, cellulase, andhemi-cellulase are disclosed in U.S. Pat. Nos. 5,806,597 and 5,067,566,incorporated herein by reference.

A breaking agent or breaker may be used “as is” or be encapsulated andactivated by a variety of mechanisms including crushing by formationclosure or dissolution by formation fluids. Such techniques aredisclosed, for example, in U.S. Pat. Nos. 4,506,734; 4,741,401;5,110,486; and 3,163,219, incorporated herein by reference.

Suitable ester compounds include any ester which is capable of assistingthe breaker in degrading the viscous fluid in a controlled manner, i.e.,providing delayed breaking initially and substantially complete breakingafter well treatment is completed. An ester compound is defined as acompound that includes one or more carboxylate groups: R—COO—, wherein Ris phenyl, methoxyphenyl, alkylphenyl, C₁-C₁₁ alkyl, C₁-C₁₁ substitutedalkyl, substituted phenyl, or other organic radicals. Suitable estersinclude, but are not limited to, diesters, triesters, etc.

An ester is typically formed by a condensation reaction between analcohol and an acid by eliminating one or more water molecules.Preferably, the acid is an organic acid, such as a carboxylic acid. Acarboxylic acid refers to any of a family of organic acids characterizedas polycarboxylic acids and by the presence of more than one carboxylgroup. In additional to carbon, hydrogen, and oxygen, a carboxylic acidmay include heteroatoms, such as S, N, P, B, Si, F, Cl, Br, and I. Insome embodiments, a suitable ester compound is an ester of oxalic,malonic, succinic, malic, tartaric, citrate, phthalic,ethylenediaminetetraacetic (EDTA), nitrilotriacetic, phosphoric acids,etc. Moreover, suitable esters also include the esters of glycolic acid.The alkyl group in an ester that comes from the corresponding alcoholincludes any alkyl group, both substituted or unsubstituted. Preferably,the alkyl group has one to about ten carbon atoms per group. It wasfound that the number of carbon atoms on the alkyl group affects thewater solubility of the resulting ester. For example, esters made fromC₁-C₂ alcohols, such as methanol and ethanol, have relatively higherwater solubility. Thus, application temperature range for these estersmay range from about 120° F. to about 250° F. (about 49° C. to about121° C.). For higher temperature applications, esters formed from C₃-C₁₀alcohols, such as n-propanol, butanol, hexanol, and cyclohexanol, may beused. Of course, esters formed from C₁₁ or higher alcohols may also beused. In some embodiments, mixed esters, such as acetyl methyl dibutylcitrate, may be used for high temperature applications. Mixed estersrefer to those esters made from polycarboxylic acid with two or moredifferent alcohols in a single condensation reaction. For example,acetyl methyl dibutyl citrate may be prepared by condensing citric acidwith both methanol and butanol and then followed by acylation.

Specific examples of the alkyl groups originating from an alcoholinclude, but are not limited to, methyl, ethyl, propyl, butyl,iso-butyl, 2-butyl, t-butyl, benzyl, p-methoxybenzyl, m-methoxybenxyl,chlorobenzyl, p-chlorobenzyl, phenyl, hexyl, pentyl, etc. Specificexamples of suitable ester compounds include, but are not limited to,triethyl phosphate, diethyl oxalate, dimethyl phthalate, dibutylphthalate, diethyl maleate, diethyl tartrate, 2-ethoxyethyl acetate,ethyl acetylacetate, triethyl citrate, acetyl triethyl citrate,tetracyclohexyl EDTA, tetra-1-octyl EDTA, tetra-n-butyl EDTA,tetrabenzyl EDTA, tetramethyl EDTA, etc. Additional suitable estercompounds are described, for example, in the following U.S. Pat. Nos.3,990,978; 3,960,736; 5,067,556; 5,224,546; 4,795,574; 5,693,837;6,054,417; 6,069,118; 6,060,436; 6,035,936; 6,147,034; and 6,133,205,incorporated herein by reference.

When an ester of a polycarboxylic acid is used, total esterification ofthe acid functionality is preferred, although a partially esterifiedcompound may also be used in place of or in addition to a totallyesterified compound. In these embodiments, phosphate esters are not usedalone. A phosphate ester refers to a condensation product between analcohol and a phosphorus acid or a phosphoric acid and metal saltsthereof. However, in these embodiments, combination of a polycarboxylicacid ester with a phosphate ester may be used to assist the degradationof a viscous gel.

When esters of polycarboxylic acids, such as esters of oxalic, malonic,succinic, malic, tartaric, citrate, phthalic, ethylenediaminetetraacetic(EDTA), nitrilotriacetic, and other carboxylic acids are used, it wasobserved that these esters assist metal based oxidizing agents (such asalkaline earth metal or zinc peroxide) in the degradation of fracturingfluids. It was found that the addition of 0.1 gal/Mgal (0.1 l/m³) to 5gal/Mgal (5 l/m³) of these esters significantly improves the degradationof the fracturing fluid. More importantly, the degradation response isdelayed, allowing the fracturing fluid ample time to create the fractureand place the proppant prior to the degradation reactions. The delayedreduction in viscosity is likely due to the relatively slow hydrolysisof the ester, which forms polycarboxylate anions as hydrolysis products.These polycarboxylate anions, in turn, improve the solubility of metalbased oxidizing agents by sequestering the metal associated with theoxidizing agents. This may have promoted a relatively rapiddecomposition of the oxidizing agent and caused the fracturing fluiddegradation.

Generally, the temperature and the pH of a fracturing fluid affects therate of hydrolysis of an ester. For downhole operations, the bottom holestatic temperature (“BHST”) cannot be easily controlled or changed. ThepH of a fracturing fluid usually is adjusted to a level to assure properfluid performance during the fracturing treatment. Therefore, the rateof hydrolysis of an ester could not be easily changed by altering BHSTor the pH of a fracturing fluid. However, the rate of hydrolysis may becontrolled by the amount of an ester used in a fracturing fluid. Forhigher temperature applications, the hydrolysis of an ester may beretarded or delayed by dissolving the ester in a hydrocarbon solvent.Moreover, the delay time may be adjusted by selecting esters thatprovide more or less water solubility. For example, for low temperatureapplications, polycarboxylic esters made from low molecular weightalcohols, such as methanol or ethanol, are recommended. The applicationtemperature range for these esters could range from about 120° F. toabout 250° F. (about 49° C. to about 121° C.). On the other hand, forhigher temperature applications or longer injection times, esters madefrom higher molecular weight alcohols should preferably be used. Thehigher molecular weight alcohols include, but are not limited to, C₃-C₆alcohols, e.g., n-propanol, hexanol, and cyclohexanol.

In some embodiments, esters of citric acid are used in formulating awell treatment fluid. A preferred ester of citric acid is acetyltriethyl citrate, which is available under the trade name Citraflex A2from Morflex, Inc., Greensboro, N.C.

Propping agents or proppants are typically added to the fracturing fluidprior to the addition of a crosslinking agent. However, proppants may beintroduced in any manner which achieves the desired result. Any proppantmay be used in embodiments of the invention. Examples of suitableproppants include, but are not limited to, quartz sand grains, glass andceramic beads, walnut shell fragments, aluminum pellets, nylon pellets,and the like. Proppants are typically used in concentrations betweenabout 1 to 8 lbs. per gallon of a fracturing fluid, although higher orlower concentrations may also be used as desired. The fracturing fluidmay also contain other additives, such as surfactants, corrosioninhibitors, mutual solvents, stabilizers, paraffin inhibitors, tracersto monitor fluid flow back, and so on.

The well treatment fluid composition in accordance with embodiments ofthe invention has many useful applications. For example, it may be usedin hydraulic fracturing, gravel packing operations, water blocking,temporary plugs for purposes of wellbore isolation and/or fluid losscontrol, and other well completion operations. One application of thefluid composition is to use it as a fracturing fluid. Accordingly,embodiments of the invention also provide a method of treating asubterranean formation. The method includes formulating a fracturingfluid comprising an aqueous fluid, a hydratable polymer, a crosslinkingagent, an inorganic breaking agent, and an ester compound; and injectingthe fracturing fluid into a bore hole to contact at least a part of theformation by the fracturing fluid under a sufficient pressure tofracture the formation. Initially, the viscosity of the fracturing fluidshould be maintained above at least 200 cP at 40 sec⁻¹ during injectionand, afterwards, should be reduced to less than 200 cP at 40 sec⁻¹.After the viscosity of the fracturing fluid is lowered to an acceptablelevel, at least a portion of the fracturing fluid is removed from theformation. During the fracturing process, a proppant can be injectedinto the formation simultaneously with the fracturing fluid. Preferably,the fracturing fluid has a pH around or above about 7, more preferablyin the range of about 8 to about 12.

It should be understood that the above-described method is only one wayto carry out embodiments of the invention. The following U.S. patentsdisclose various techniques for conducting hydraulic fracturing whichmay be employed in embodiments of the invention with or withoutmodifications: U.S. Pat. Nos. 6,169,058; 6,135,205; 6,123,394;6,016,871; 5,755,286; 5,722,490; 5,711,396; 5,551,516; 5,497,831;5,488,083; 5,482,116; 5,472,049; 5,411,091; 5,402,846; 5,392,195;5,363,919; 5,228,510; 5,074,359; 5,024,276; 5,005,645; 4,938,286;4,926,940; 4,892,147; 4,869,322; 4,852,650; 4,848,468; 4,846,277;4,830,106; 4,817,717; 4,779,680; 4,479,041; 4,739,834; 4,724,905;4,718,490; 4,714,115; 4,705,113; 4,660,643; 4,657,081; 4,623,021;4,549,608; 4,541,935; 4,378,845; 4,067,389; 4,007,792; 3,965,982; and3,933,205, incorporated herein by reference.

The liquid carrier can generally be any liquid carrier suitable for usein oil and gas producing wells. A presently preferred liquid carrier iswater. The liquid carrier can comprise water, can consist essentially ofwater, or can consist of water. Water will typically be a majorcomponent by weight of the fluid. The water can be potable ornon-potable water. The water can be brackish or contain other materialstypical of sources of water found in or near oil fields. For example, itis possible to use fresh water, brine, or even water to which any salt,such as an alkali metal or alkali earth metal salt (NaCO.sub.3, NaCl,KCl, etc.) has been added. The liquid carrier is preferably present inan amount of at least about 80% by weight. Specific examples of theamount of liquid carrier include 80%, 85%, 90%, and 95% by weight. Thecarrier liquid can be a VAS gel.

The pH of the fluid can generally be any pH compatible with downholeformations. The pH is presently preferred to be about 6.5 to about 10.0.The pH can be about the same as the formation pH.

The surfactant can generally be any surfactant. The surfactant ispreferably viscoelastic. The surfactant is preferably anionic. Theanionic surfactant can be an alkyl sarcosinate. The alkyl sarcosinatecan generally have any number of carbon atoms. Presently preferred alkylsarcosinates have about 12 to about 24 carbon atoms. The alkylsarcosinate can have about 14 to about 18 carbon atoms. Specificexamples of the number of carbon atoms include 12, 14, 16, 18, 20, 22,and 24 carbon atoms.

The anionic surfactant can have the chemical formula R₁ CON(R₂)CH₂X,wherein R₁ is a hydrophobic chain having about 12 to about 24 carbonatoms, R₂ is hydrogen, methyl, ethyl, propyl, or butyl, and X iscarboxyl or sulfonyl. The hydrophobic chain can be an alkyl group, analkenyl group, an alkylarylalkyl group, or an alkoxyalkyl group.Specific examples of the hydrophobic chain include a tetradecyl group, ahexadecyl group, an octadecentyl group, an octadecyl group, and adocosenoic group.

The surfactant can generally be present in any weight percentconcentration. Presently preferred concentrations of surfactant areabout 0.1% to about 15% by weight. A presently more preferredconcentration is about 0.5% to about 6% by weight. Laboratory procedurescan be employed to determine the optimum concentrations for anyparticular situation.

The amphoteric polymer can generally be any amphoteric polymer. Theamphoteric polymer can be a nonionic water-soluble homopolysaccharide oran anionic water-soluble polysaccharide. The polymer can generally haveany molecular weight, and is presently preferred to have a molecularweight of at least about 500,000.

The polymer can be a hydrolyzed polyacrylamide polymer. The polymer canbe a scleroglucan, a modified scleroglucan, or a scleroglucan modifiedby contact with glyoxal or glutaraldehyde. The scleroglucans arenonionic water-soluble homopolysaccharides, or water-soluble anionicpolysaccharides, having molecular weights in excess of about 500,000,the molecules of which consist of a main straight chain formed ofD-glucose units which are bonded by β-1,3-bonds and one in three ofwhich is bonded to a side D-glucose unit by means of a β-1,6 bond. Thesepolysaccharides can be obtained by any of the known methods in the art,such as fermentation of a medium based on sugar and inorganic saltsunder the action of a microorganism of Sclerotium type A. A morecomplete description of such scleroglucans and their preparations may befound, for example, in U.S. Pat. Nos. 3,301,848 and 4,561,985,incorporated herein by reference. In aqueous solutions, the scleroglucanchains are combined in a triple helix, which explains the rigidity ofthe biopolymer, and consequently its features of highviscosity-increasing power and resistance to shearing stress.

It is possible to use, as source of scleroglucan, the scleroglucan whichis isolated from a fermentation medium, the product being in the form ofa powder or of a more or less concentrated solution in an aqueous and/oraqueous-alcoholic solvent. Scleroglucans customarily used inapplications in the petroleum field are also preferred according to thepresent invention, such as those which are white powders obtained byalcoholic precipitation of a fermentation broth in order to removeresidues of the producing organism (mycelium, for example).Additionally, it is possible to use the liquid reaction mixtureresulting from the fermentation and containing the scleroglucan insolution. According to the present invention, further suitablescleroglucans are the modified scleroglucan which result from thetreatment of scleroglucans with a dialdehyde reagent (glyoxal,glutaraldehyde, and the like), as well as those described in U.S. Pat.No. 6,162,449, incorporated herein by reference, (β-1,3-scleroglucanswith a cross-linked 3-dimensional structure produced by Sclerotiumrolfsii).

The polymer can be Aquatrol V (a synthetic compound which reduces waterproduction problems in well production; described in U.S. Pat. No.5,465,792, incorporated herein by reference), AquaCon (a moderatemolecular weight hydrophilic terpolymer based on polyacrylamide capableof binding to formation surfaces to enhance hydrocarbon production;described in U.S. Pat. No. 6,228,812, incorporated herein by reference)and Aquatrol C (an amphoteric polymeric material). Aquatrol V, AquatrolC, and AquaCon are commercially available from BJ Services Company.

The polymer can be a terpolymer synthesized from an anionic monomer, acationic monomer, and a neutral monomer. The monomers used preferablyhave similar reactivities so that the resultant amphoteric polymericmaterial has a random distribution of monomers. The anionic monomer cangenerally be any anionic monomer. Presently preferred anionic monomersinclude acrylic acid, methacrylic acid, 2-acrylamide-2-methylpropanesulfonic acid, and maleic anhydride. The cationic monomer can generallybe any cationic monomer. Presently preferred cationic monomers includedimethyl-diallyl ammonium chloride, dimethylamino-ethyl methacrylate,and allyltrimethyl ammonium chloride. The neutral monomer can generallybe any neutral monomer. Presently preferred neutral monomers includebutadiene, N-vinyl-2-pyrrolidone, methyl vinyl ether, methyl acrylate,maleic anhydride, styrene, vinyl acetate, acrylamide, methylmethacrylate, and acrylonitrile. The polymer can be a terpolymersynthesized from acrylic acid (AA), dimethyl diallyl ammonium chloride(DMDAC) or diallyl dimethyl ammonium chloride (DADMAC), and acrylamide(AM). The ratio of monomers in the terpolymer can generally be anyratio. A presently preferred ratio is about 1:1:1.

Another presently preferred amphoteric polymeric material (hereinafter“polymer 1”) includes approximately 30% polymerized AA, 40% polymerizedAM, and 10% polymerized DMDAC or DADMAC with approximately 20% freeresidual DMDAC or DADMAC which is not polymerized due to lower relativereactivity of the DMDAC or DADMAC monomer.

The fluid can further comprise one or more additives. The fluid canfurther comprise a base. The fluid can further comprise a salt. Thefluid can further comprise a buffer. The fluid can further comprise arelative permeability modifier. The fluid can further comprisemethylethylamine, monoethanolamine, triethylamine, triethanolamine,sodium hydroxide, potassium hydroxide, potassium carbonate, sodiumchloride, potassium chloride, potassium fluoride, KH₂PO₄, or K₂HPO₄. Thefluid can further comprise a proppant. Conventional proppants will befamiliar to those skilled in the art and include sand, resin coated sandsintered bauxite and similar materials. The proppant can be suspended inthe fluid.

Relative permeability modifiers can be added to the fluids to furtherimprove water shut off properties. These compounds are polymers that arewater-soluble and improve the leak-off viscosity of the fracturingfluid.

A specific example of a treating fluid is as follows: (a) 11% KCl byweight; (b) 2.5% surfactant by weight; (c) 1.6% buffer (potassiumcarbonate in water (45% by weight potassium carbonate)) by volume, and(d) 1.0% of 10% (by weight) Polymer 1 solution.

An additional embodiment of the invention involves the use of any of theabove described fluids in a method of fracturing a subterraneanformation. The method can comprise providing a fluid comprising a liquidcarrier, a viscoelastic anionic surfactant, and an amphoteric polymer,pumping the fluid through a wellbore, and contacting the fluid and thesubterranean formation to fracture the formation.

A further additional embodiment of the invention involves the use of anyof the above described fluids in a method of reducing the amount ofwater produced from a subterranean oil producing formation. The methodcan comprise providing a fluid comprising a liquid carrier, aviscoelastic anionic surfactant, and an amphoteric polymer, pumping thefluid through a wellbore, contacting the fluid and the subterraneanformation, and obtaining product from the formation. The weight percentof water in the product is less than the weight percent of water inproduct produced from a similar formation that was not contacted withthe fluid. The fluid can further comprise a relative permeabilitymodifier. The C_(w) of the similar formation that was not treated withthe fluid (“untreated C_(w)”) is preferably greater than the C_(w) ofthe formation treated with the fluid (“treated C_(w)”). The ratio of theuntreated C_(w) to the treated C_(w) is preferably at least about 2, atleast about 5, at least about 10, at least about 20, at least about 30,at least about 40, at least about 50, at least about 60, at least about70, at least about 80, at least about 90, at least about 100, at leastabout 150, or at least about 200.

According to other embodiments of the invention, there is provided afracturing fluid comprising anionic viscoelastic surfactants whichviscosify and its leak-off viscosity can be enhanced while the fluid isinjected in the pores of the rock, providing water shut off and favoringoil/gas flow and allowing non damaging polymers such as relativepermeability modifiers to be included in the formulations withoutadversely affecting the gel viscosity but improving the gel filtrationefficiency and its water control properties.

Some embodiments of the invention take advantage of the natural pHchange at the formation rock to cause an increase in the gel viscosityat the formation pores to block water production, which is discussedherein. For example, in its use the fluid is designed for optimumviscosity at the same pH of the formation water/rock. However it ispumped at a pH that is lower or higher than the formation pH (0.3 to 1unit) through a wellbore and into a surrounding formation having anaqueous zone and a hydrocarbon zone. The fluid is then allowed tocontact the aqueous zone and the hydrocarbon zone. Contact with thehydrocarbon zone serves to thin the fluid since the surfactant gel isthinned by hydrocarbons. While contact with the water zone or watersaturated pores will lower the gel pH to that of the formationincreasing its viscoelasticity and viscosity. Additionally, if an RPMpolymer is included in the formulation it will adhere to the water wetrock and induce a drag, or friction force on water, reinforcing theviscoelastic gel structure and also lubricating oil production, servingto preferentially block the flow of water from that portion of theformation. Consequently oil production is unaffected while water flow ispreferentially shut off.

The amphoteric polymeric material is characterized by the presence ofboth positively and negatively charged components along the polymerchain. This nature of the polymeric material is believed to account forthe polymeric material's ability to strongly bond to the formation whileexhibiting a hydrophilic character capable of forming a strong hydrogenbond to water causing a drag or a higher friction pressure on waterflowing through the capillaries or openings of the formation. Bywhatever mechanism, the mobility of formation water is greatly reducedby the amphoteric polymeric material without restricting the productionof oil or gas to any. appreciable extent.

Additional description of various embodiments of the invention areprovided below. The description with respect to “well-treatingsolution”, and “viscous fluid” is applicable, with or withoutmodifications, to the well service fluid in accordance with embodimentsof the invention. It should be noted that any number disclosed hereinshould be understood as to mean an approximate value, regardless ofwhether the word “about” or “approximate” is used in describing thenumber.

A presently preferred well treating solution for changing the relativepermeability of a formation to water can be prepared by adding theamphoteric polymeric material to VAS carrier liquid with the amphotericpolymeric material being present at about 1.0% to about 10% by volume,depending upon the permeability.

The resulting treating solution can be injected into the formation atpumping rates and treating pressures above the fracture gradient of theformation. The volume of treating solution used is based on the desiredfracture geometry, the thickness of the zone to be treated, the porosityof the formation being treated, and other factors.

The viscous fluids of the invention can be used for transportingparticulate through a conduit to a subterranean location. In one form,the fluids comprise an aqueous base, a surfactant comprising an alkylsarcosinate having from about 12 to about 24 carbon atoms and a bufferfor adjusting the pH of the combined aqueous base and surfactant at orfor the formation pH. The alkyl sarcosinate is preferably present atabout 0.5% to about 10% by weight, based upon the weight of the totalfluid. The pH of the viscous fluid is preferably adjusted with thebuffer to about 6.5 to about 10.0 for most formations.

The viscous fluids of the invention can also include an additionalsource of anions in addition to those furnished by the surfactant. Theadditional source of anions can be a co-surfactant such as any ionic oranionic undiluted surfactant.

In the method of fracturing a subterranean formation of the invention,an aqueous base fluid is combined with a surfactant comprising an alkylsarcosinate having from about 12 to about 24 carbon atoms. The combinedfluid is buffered to thereby adjust the pH of the combined aqueous baseand surfactant at or for the formation pH, thereby creating a viscousfluid capable of supporting proppant. The viscous fluid is pumpedthrough a wellbore and into a surrounding formation at a pressuresufficient to fracture the formation.

The viscous fluids of the invention can also be used in a method forreducing the amount of water produced from a subterranean oil producingformation. An aqueous base fluid is combined with a surfactantcomprising an alkyl sarcosinate having from about 12 to about 24 carbonatoms. The combined fluid is buffered to thereby adjust the pH of thecombined aqueous base and surfactant sufficiently to produce a viscousfluid. The viscous fluid is pumped through a wellbore and into asurrounding formation having an aqueous zone and a hydrocarbon zone, theaqueous zone comprising water. The viscous fluid is then allowed tocontact the aqueous zone and the hydrocarbon zone. Contact with thehydrocarbon zone serves to thin the viscous fluid while contact with theaqueous zone serves to preferentially block the flow of water from thatportion of the formation.

The viscoelastic surfactant fluid is useful as a fracturing fluid withimproved efficiency. Specifically, the use of this fluid in fracturing aformation will simultaneously enhance oil production whilesimultaneously drastically minimizing or completely stopping waterproduction.

In a preferred form, the viscous fluids of the invention comprise water,a base, a surfactant comprising an alkyl sarcosinate having from about12 to about 24 carbon atoms in the alkyl group, and a buffer foradjusting the pH, of the combined aqueous base and surfactant at or forthe formation pH. As will be explained in detail, the fluids of theinvention can be optimized for viscosity and for the formation pH inorder to reduce ion exchange at the formation, thereby avoiding claydispersion and swelling. The water used in formulating the fluids can befresh water or light brines from any convenient source. The particularlypreferred alkyl sarcosinates used as the surfactant have an alkyl groupof about 14 to about 18 carbon atoms.

Sarcosine (N-methylglycine) is a naturally occurring amino acid found instarfish, sea urchins and crustaceans. It can be purchased from avariety of commercial sources, or alternately produced by a number ofsynthetic routes known in the art including thermal decomposition ofcaffeine in the presence of barium hydroxide (Arch. Pharm. 232: 601,1894); (Bull. Chem. Soc. Japan, 39: 2535, 1966); and numerous others (T.Shirai in Synthetic Production and Utilization of Amino Acids; T.Kaneko, et al., Eds.; Wiley, New York: pp. 184-186, 1974). Sodiumsarcosinate is manufactured commercially from formaldehyde, sodiumcyanide and methyl amine (U.S. Pat. Nos. 2,720,540 and 3,009,954). Thepreferred sarcosinate are the condensation products of sodiumsarcosinate and a fatty acid chloride. The fatty acid chloride isreacted with sodium sarcosinate under carefully controlled alkalineconditions (i.e., the Schotten-Bauman reaction) to produce the fattysarcosinate sodium salt which is water soluble. Upon acidification, thefatty sarcosine acid, which is also water insoluble, is formed and maybe isolated from the reaction medium. The acyl sarcosines may beneutralized with bases such as the salts of sodium, potassium, ammonia,or organic bases such as triethanolamine in order to produce aqueoussolutions.

Another surfactant useful in the fluids of this invention are an anionicsarcosinate surfactant available commercially from BJ Services Companyas “M-Aquatrol” (MA). The MA-1 sarcosinate is a viscous liquidsurfactant with at least 94% oleoyl sarcosine. For hydraulic fracturing,a sufficient quantity of the sarcosinate is present in aqueous solutionto provide sufficient viscosity to suspend proppant during placement.The surfactant is preferably present at about 0.5% to about 10% byweight, most preferably at about 0.5% to about 6% by weight, based uponthe weight of the total fluid.

The surfactant can be added to an aqueous solution in which there istypically dissolved a quantity of at least one water soluble salt toeffect formation stability. Typical water-soluble salts includepotassium chloride, sodium chloride and the like. Formation stability istypically achieved with only small concentrations of salt. Thewater-soluble salts may be considered part of the “buffer” for adjustingthe pH of the combined aqueous base and surfactant in the method of thepresent invention. The viscosity of the fluids of the invention areimproved significantly by the addition of certain additional anions tothe surfactant-laden solution. The pH can be adjusted, for example, bythe addition of alkali metal, carbonate, phosphate or borate, or organicamines, especially alkanol amines such as mono-, di- or triethanolamine.

High temperature stability of the fluids in question is achieved ifselecting specific anion, such as phosphate or fluoride ions instead ofchlorides, preferably provided in the form of an inorganic phosphate orfluoride salt or a fluoride acid such as fluosilicic acid (H.sub.2SiF.sub.6). The fluoride salt concentration can be about 0.5% to about10% by weight, and more preferably about 3% to about 7% by weight, basedupon the total weight of the fluid. Typical fluoride salts includeammonium bifluoride and potassium fluoride. The pH of thesurfactant-fluoride salt solution can be adjusted to about 6.5 to about10. The pH can be adjusted with the same bases as discussed above.

Each salt will produce a peak viscosity at a different pH. The fluids ofinvention are optimized for viscosity and formation pH as will bediscussed with respect to the laboratory analyses which follow.

In the method of fracturing a formation using the formulations of theinvention, an aqueous base fluid is combined with an anionic surfactantcomprising an alkyl sarcosinate having from about 12 to about 24 carbonatoms, and alternatively a viscoelastic polymer such as an RPM. Standardmixing procedures known in the art can be employed since heating of thesolution or special agitation procedures are not normally required. Theaqueous base has been buffered with a buffer to thereby adjust the pH ofthe combined aqueous base and surfactant above about 6.5, therebycreating a viscous fluid capable of supporting proppant. The proppantcan be added and the viscous fluid can then be pumped through a wellboreand into a surrounding formation at a pressure sufficient to fracturethe formation. Typically, the viscous fluid can be allowed to contactthe formation for a period of tine sufficient to increase the viscosityin the water saturated pores, while in the oil pores it will thinimmediately and therefore no breakers are required.

These effects cannot be easily achieved when cationic surfactants areused. Due to the fact that cationic surfactants are not pH dependentwith regards to viscosity, their viscosity remains within a narrow,unadjustable range, thereby limiting their utility. The anionicsurfactants of the present invention overcome this problem by being pHdependent with regards to viscosity, thereby allowing for theirviscosity to be adjusted to the desired value by altering the pHappropriately.

The fluid of the present invention may also be used asasphaltene-dispersing agents. Asphaltenes are constituents of crudeoils, usually present as colloidal dispersions stabilized by resins inthe oil. While examples of asphaltene-dispersing agents are know in theart (e.g. U.S. Pat. No. 5,948,237), the sarcosinate anionic surfactantof the invention in combination with RPM type materials produces asynergistic effect in this regard. Specifically, these compounds incombination form an excellent asphaltene-dispersant, thereby aiding inthe cleaning of rocks, pipes, valves, conveying devices, and the like byremoving heavy oil deposits and asphaltenes themselves.

The fluids of the invention can also be used as selective water controladditives. The viscous fluids can be pumped into a water rich sector ofa producing interval. Once placed, the gel viscosity will preventformation water flow through that portion of the reservoir. On the otherhand, gel pumped into the oil rich sector of the formation reservoirwill immediately thin on contact with the oil contained within thereservoir. Consequently, oil production will be uninhibited while waterflow will be preferentially stopped or significantly reduced.

For fracturing applications, the fluids of the invention are typicallypumped downhole at or slightly above the formation pH. Preferably, whenthe fluids of the invention are used for water control purposes, thefluids are pumped downhole at about 3/10 of a pH unit less or more thanthe formation material pH depending on the anion portion of the saltused as counter cation. The fluid is thus pumped in a thinned state,reducing the friction pressure of the pumping job. Upon contacting theformation material, the pH of the fluid increases, resulting in completegellation of the fluid at the formation location rather than at the wellsurface.

Various amine oxides have been used as surfactants to create foams andremove “intrusion fluids from wellbores,” according to U.S. Pat. No.3,303,896, incorporated herein by reference, and they have been used asfoam stabilizers, according to U.S. Pat. No. 3,317,430, incorporatedherein by reference. Certain amine oxides have also been used incombination with quaternary ammonium compounds as foaming and siltsuspending agents. See, for example, U.S. Pat. No. 4,108,782 and U.S.Pat. No. 4,113,631, incorporated herein by reference. The use of amineoxide surfactants for chemical flooding enhanced oil recovery wasdescribed in a topical report by David K. Olsen in NIPER-417 (August1989) for work performed for the US Department of Energy undercooperative agreement DE-FC22-83FE60149 by the National Institute forPetroleum and Energy Research. However, to Applicants' knowledge, theamine oxides have not been used to improve the properties of fracturingfluids and to promote rapid cleanup, or to enhance well production froma well stimulated by hydraulic fracturing.

Hydraulic fracturing of subterranean formations has long beenestablished as an effective means to stimulate the production ofhydrocarbon fluids from a wellbore. In hydraulic fracturing, a wellstimulation fluid (generally referred to as a fracturing fluid or a“frac fluid”) is injected into and through a wellbore and against thesurface of a subterranean formation penetrated by the wellbore at apressure at least sufficient to create a fracture in the formation.Usually a “pad fluid” is injected first to create the fracture and thena fracturing fluid, often bearing granular propping agents, is injectedat a pressure and rate sufficient to extend the fracture from thewellbore deeper into the formation. If a proppant is employed, the goalis generally to create a proppant filled zone (aka, the proppant pack)from the tip of the fracture back to the wellbore. In any event, thehydraulically induced fracture is more permeable than the formation andit acts as a pathway or conduit for the hydrocarbon fluids in theformation to flow to the wellbore and then to the surface where they arecollected. The methods of fracturing are well known and they may bevaried to meet the user's needs, but most follow this general procedure(which is greatly overly simplified).

The fluids used as fracturing fluids have also been varied, but many ifnot most are aqueous based fluids that have been “viscosified” orthickened by the addition of a natural or synthetic polymer(cross-linked or uncross-linked). The carrier fluid is usually water ora brine (e.g., dilute aqueous solutions of sodium chloride and/orpotassium chloride). The viscosifying polymer is typically a solvatable(or hydratable) polysaccharide, such as a galactomannan gum, aglycomannan gum, or a cellulose derivative. Examples of such polymersinclude guar, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxyethyl guar, hydroxyethyl cellulose,carboxymethyl-hydroxyethyl cellulose, hydroxypropyl cellulose, xanthan,polyacrylamides and other synthetic polymers. Of these, guar,hydroxypropyl guar and carboxymethlyhydroxyethyl guar are typicallypreferred because of commercial availability and cost performance.

In many instances, if not most, the viscosifying polymer is crosslinkedwith a suitable crosslinking agent. The crosslinked polymer has an evenhigher viscosity and is even more effective at carrying proppant intothe fractured formation. The borate ion has been used extensively as acrosslinking agent, typically in high pH fluids, for guar, guarderivatives and other galactomannans. See, for example, U.S. Pat. No.3,059,909, incorporated herein by reference and numerous other patentsthat describe this classic aqueous gel as a fracture fluid. Othercrosslinking agents include, for example, titanium crosslinkers (U.S.Pat. No. 3,888,312, incorporated herein by reference), chromium, iron,aluminum, and zirconium (U.S. Pat. No. 3,301,723, incorporated herein byreference). Of these, the titanium and zirconium crosslinking agents aretypically preferred. Examples of commonly used zirconium crosslinkingagents include zirconium triethanolamine complexes, zirconiumacetylacetonate, zirconium lactate, zirconium carbonate, and chelants oforganic alphahydroxycorboxylic acid and zirconium. Examples of commonlyused titanium crosslinking agents include titanium triethanolaminecomplexes, titanium acetylacetonate, titanium lactate, and chelants oforganic alphahydroxycorboxylic acid and titanium.

Additional information on fracturing is found in the description byJanet Gulbis and Richard M. Hodge in Chapter 7 of the text “ReservoirStimulation” published by John Wiley & Sons, Ltd, Third Edition, 2000(Editors, Michael J. Economides and Kenneth G. Nolte), which isincorporated herein by reference. Some fracturing fluids have also beenenergized by the addition of a gas (e.g., nitrogen or carbon dioxide) tocreate a foam. See, for example, the pioneering work by Roland E. Blauerand Clarence J. Durborow in U.S. Pat. No. 3,937,283, incorporated hereinby reference (“Formation Fracturing with Stable Foam”). The rheology ofthe traditional water-base polymer solutions and also complex fluids,such as foams, can be and typically is modified and augmented by severaladditives to control their performance. Fluid loss additives aretypically added to reduce the loss of fracturing fluids into theformation.

The problems associated with the loss of fracturing fluid to theformation are well known. For example, in 1978 Holditch reported: “Thefluid injected during the fracturing treatment will leak off into theformation and will reduce the relative permeability to gas in theinvaded region. Near the fracture, the permeability to gas will bereduced to zero.” In addition, Holditch said: “In some cases, theinjected fracturing fluid may reduce the formation permeability in theinvaded zone.” Stephen A. Holditch, SPE 7561 (Presented at the 53^(rd)Annual Fall Technical Conference and Exhibition of the Society ofPetroleum Engineers of AIME, held in Houston, Tex., Oct. 1-3, 1978). Thedamage to the formation could be severe, and the practical so what ofthat is reduced flow of hydrocarbons, low production and poor economicson the well. While the state of the art has advanced substantially sinceHolditch reported on the problems associated with leak off of fracturingfluid, the problems remain the same. See, for example, Vernon G.Constien, George W. Hawkins, R. K. Prud'homme and Reinaldo Navarrete,Chapter 8 entitled “Performance of Fracturing Materials” and the otherchapters on fracturing and well stimulation in “Reservoir Stimulation”published by John Wiley & Sons, Ltd, Third Edition, copyrightSchlumberger 2000 (Editors, Michael J. Economides and Kenneth G. Nolte),the disclosure of which is incorporated herein by reference. Theseauthors and others emphasize the importance of “cleanup” or “fracturecleanup” to optimize production of the hydrocarbon fluids from the well.The term “cleanup” or “fracture cleanup” refers to the process ofremoving the fracture fluid (without the proppant) from the fractureafter the fracturing process has been completed. Techniques forpromoting fracture cleanup often involved reducing the viscosity of thefracture fluid as much as practical so that it will more readily flowback toward the wellbore. So-called “breakers” have been used to reducefluid viscosity in many instances. The breakers can be enzymes(oxidizers and oxidizer catalysts), and they may be encapsulated todelay their release. See, for example, U.S. Pat. No. 4,741,401,incorporated herein by reference. Another technique to aid in thecleanup, albeit by a contrarian approach, is found in U.S. Pat. No.6,283,212, incorporated herein by reference.

Hydraulic fracturing is a primary tool for improving well productivityby placing or extending channels from the wellbore to the reservoir.This operation is essentially performed by hydraulically injecting afracturing fluid into a wellbore penetrating a subterranean formationand forcing the fracturing fluid against the formation strata bypressure. The formation strata or rock is forced to crack and fracture.Proppant is placed in the fracture to prevent the fracture from closingand thus, provide improved flow of the recoverable fluid, i.e., oil, gasor water.

The proppant is thus used to hold the walls of the fracture apart tocreate a conductive path to the wellbore after pumping has stopped.Placing the appropriate proppant at the appropriate concentration toform a suitable proppant pack is thus critical to the success of ahydraulic fracture treatment.

Sand, resin-coated sand, and ceramic particles are the most commonlyused proppants, though the literature, for instance U.S. Pat. No.4,654,266, incorporated herein by reference, also mentions the used ofwalnut hull fragments coated with some bonding additives, metallicshots, or metal-coated beads—nearly spherical but having a passagewaysto improve their conductibility.

The proppant conductivity is affected principally by two parameters, theproppant pack width and the proppant pack permeability. To improvefracture proppant conductivity, typical approaches include high largediameter proppants. More generally, the most common approaches toimprove proppant fracture performance include high strength proppants,large diameter proppants, high proppant concentrations in the proppantpack to obtain wider propped fractures, conductivity enhancing materialssuch as breakers, flow-back aides, fibers and other material thatphysically alter proppant packing, and use of non-damaging fracturingfluids such as gelled oils, viscoelastic surfactant based fluids, foamedfluids or emulsified fluids. It is also recognized that grain size,grain-size distribution, quantity of fines and impurities, roundness andsphericity and proppant density have an impact on fracture conductivity.

As mentioned above, the main function of the proppant is to keep thefracture open by overcoming the in-situ stress. Where the proppantstrength is not high enough, the closure stress crushes the proppant,creating fines and reducing the conductivity. Sand is typically suitablefor closure stresses of less than about 6000 psi (41 MPa), resin-coatedsand may be used up to about 8000 psi (55 MPa). Intermediate-strengthproppant typically consists of fused ceramic or sintered-bauxite and isused for closure stresses ranging between 5000 psi and 10000 psi (34 MPato 69 MPa). High-strength proppant, consisting of sintered-bauxite withlarge amounts of corundum is used at closure stresses of up to about14000 psi (96 MPa).

Permeability of a propped fracture increases as the square of the graindiameter. However, larger grains are often more susceptible to crush,have more placement problems and tend to be more easily invaded byfines. As the result, the average conductivity over the life of a wellmay be actually higher with smaller proppants.

In an effort to limit the flowback of particulate proppant materialsplaced into the formation, it was disclosed in U.S. Pat. No. 5,330,005,incorporated herein by reference, to add some fibrous material, mixedwith the proppant material. It is believed that the fibers becomeconcentrated into a mat or other three-dimensional framework, whichholds the proppant thereby limiting its flowback. The fibers can be ofglass, ceramic, carbon, natural or synthetic polymers or metal fibers.They have a length of typically about 2 to 30 mm and a diameter ofbetween 10 and 100 micrometers. According to U.S. Pat. No. 5,908,073,incorporated herein by reference, the flowback is prevented through theuse of fibrous bundles, made of from about 5 to about 200 individualfibers having lengths in the range of about 0.8 to about 2.5 mm anddiameters in the range of about 10 to about 1000 micrometers. It hasalso known from U.S. Pat. No. 6,059,034, incorporated herein byreference, to add to blend the proppant material with a deformableparticulate material. The deformable particles may have different shapessuch as oval, cubic, bar-shaped, cylindrical, multi-faceted, irregular,tapered—but preferably with a maximum length-based ratio equal or lessthan 5, and are typically spherical plastic beads or composite particlescomprising a non-deformable core and a deformable coating. In anotherembodiment claimed in U.S. Pat. No. 6,330,916, incorporated herein byreference, the particles may comprise ground or crushed materials suchas nutshells, seed shells, fruit pits, and processed woods.

It should be emphasized that in all of the four above-mentioned U.S.Patents, the proppant itself is constituted of essentially sphericalparticles—most typically sand—intermingled with a material that may beelongated. This reflects the general understanding of this art thatangular grains fail at lower closure stresses, producing more fines andthus reducing fracture conductivity. On the other hand, round anduniform-sized grains result in higher loads before failure sincestresses are more evenly distributed.

Adding fibers or fiber-like products to the products may contribute to areduction of the proppant flowback—and consequently to a better packingof the proppant in the fracture. Additionally, they contribute toprevent fine migrations and consequently, to prevent a reduction of theproppant conductivity but there is still a need for a new type ofproppant that will lead to higher conductivity.

According to the invention, the solid organic polymeric particulatematter composition is selected for its ultimate and delayed reactivityand/or degradation characteristics in providing the required gelbreaking action and cleanup, it being required, of course, that itsreactivity or degradation in the fluid suspension be sufficientlygradual, delayed, or retarded (delayed) that formation of a gel by thesuspension is not significantly inhibited or the gelled suspensionbroken before the fracturing operation is carried out to the desiredextent. That is, the solid organic polymeric particulate matter shouldnot react with other components of the fluid or the particles to beremoved and/or transported or the formation components, or decompose ordegrade in the fluid suspension, at a rate faster than desired. Thesuitability of a particular solid organic polymeric particulate materialor composition(s) may be determined by testing, as illustratedhereinafter, and a composition or compositions may be prepared, forexample, by blending, or may be chosen, which degrade or decompose at arate corresponding to the time required for carrying out the fracturingoperation, as determined by such testing. Accordingly, the solid organicpolymeric particulate matter employed in the invention may be chosenfrom a wide variety of organic polymeric materials of the typementioned, provided the particles possess such delayed reactivity and/ordecomposition characteristics. Thus, natural and synthetic organicpolymers or elastomers having an average molecular weight of at least10,000, preferably at least 15,000 to 18,000, and most preferably atleast 100,000, as determined by size exclusion chromatography or othersuitable method, having the required reactivity and/or decompositioncharacteristics, may be employed. As utilized herein, the expressions“organic polymeric”, as applied to “compound” and to “material”, and“organic polymer” and “polymer”, are understood to include not onlypolymerization products of a monomer, but copolymers, terpolymers, etc.Additionally, all types of mixtures of the mentioned materials may beemployed. For example, suitable polymeric particulate matter derivedfrom cellulose, acrylic acid, aramides, acrylonitrile, polyamides,vinylidene, olefins, diolefins, polyester, polyurethane, vinyl alcohol,and vinyl chloride, may be used. Preferred compositions, assuming therequired reactivity and/or decomposition characteristics may be selectedfrom rayon, acetate, triacetate, cotton, wool (cellulose group); nylon,acrylic, modacrylic, nitrile, polyester, saran, spandex, vinyon, olefin,vinyl, (synthetic polymer group); azlon, rubber (protein and rubbergroup), and mixtures thereof. Polyester and polyamide particles ofsufficient molecular weight, such as from Dacron® and nylon,respectively, and mixtures thereof, are most preferred. Again, compositeparticles, comprising natural and/or synthetic materials of appropriatecharacteristics, may be employed. For example, a suitable compositeparticle might comprise a core and sheath structure where the sheathmaterial and the core material degrade over different desired periods oftime. The compounds or compositions employed as organic polymericmaterial according to the invention need not be pure, and commerciallyavailable materials containing various additives, fillers, etc. orhaving coatings may be used, so long as such components do not interferewith the required activity.

As indicated, the amount of the organic polymeric particulate mattersupplied will be sufficient for the task required, i.e., a sufficient oreffective amount, an amount sufficient to provide a sufficientconcentration of a composition or compositions which are effective todegrade the gelled suspension to the desired degree. Normally, as alsoindicated, this composition or compositions will comprise one or more ofthe ultimate reaction or decomposition products of the organic polymericmaterial. Preferably, the organic polymeric particulate matter level,i.e., concentration, provided initially in the fluid may range from 0.02percent up to about 10 percent by weight of the fluid. Most preferably,however, the concentration ranges from about 0.02 percent to about 5.0percent by weight of fluid.

Particle size and shape, while important, may be varied considerably,depending on timing and transport considerations. Preferably, ifirregular or spherical particles of the organic polymer are used,particle size may range from 80 mesh to 2.5 mesh (Tyler), preferablyfrom 60 mesh to 3 mesh. Fibers and/or platelets of the specifiedpolymeric materials are preferred for their mobility and transfer aidingcapability. In the case of fibers of the organic polymer, the fibersemployed according to the invention may also have a wide range ofdimensions and properties. As employed herein, the term “fibers” refersto bodies or masses, such as filaments, of natural or syntheticmaterial(s) having one dimension significantly longer than the othertwo, which are at least similar in size, and further includes mixturesof such materials having multiple sizes and types. Preferably, inaccordance with the invention, individual fiber lengths may rangeupwardly from about 1 millimeter. Practical limitations of handling,mixing, and pumping equipment in wellbore applications, currently limitthe practical use length of the fibers to about 100 millimeters.Accordingly, a preferred range of fiber length will be from about 1 mmto about 100 mm or so, with a most preferred length being from at leastabout 2 mm up to about 30 mm. Similarly, fiber diameters will preferablyrange upwardly from about 5 microns, a preferred range being from about5 microns to about 40 microns, most preferably from about 8 microns toabout 20 microns, depending on the modulus of the fiber, as describedmore fully hereinafter. A ratio of length to diameter (assuming thecross section of the fiber to be circular) in excess of 50 is preferred.However, the fibers may have a variety of shapes ranging from simpleround or oval cross-sectional areas to more complex shapes such astrilobe, figure eight, star-shape, rectangular cross-sectional, or thelike. Preferably, generally straight fibers with round or oval crosssections will be used. Curved, crimped, branched, spiral-shaped, hollow,fibrillated, and other three dimensional fiber geometries may be used.Again, the fibers may be hooked on one or both ends. Fiber and plateletdensities are not critical, and will preferably range from below 1 to 4g/cm³ or more.

Those skilled in the art will recognize that a dividing line betweenwhat constitute “platelets”, on one hand, and “fibers”, on the other,tends to be arbitrary, with platelets being distinguished practicallyfrom fibers by having two dimensions of comparable size both of whichare significantly larger than the third dimension, fibers, as indicated,generally having one dimension significantly larger than the other two,which are similar in size. As used herein, the terms “platelet” or“platelets” are employed in their ordinary sense, suggesting flatness orextension in two particular dimensions, rather than in one dimension,and also is understood to include mixtures of both differing types andsizes. In general, shavings, discs, wafers, films, and strips of thepolymeric material(s) may be used. Conventionally, the term “aspectratio” is understood to be the ratio of one dimension, especially adimension of a surface, to another dimension. As used herein, the phraseis taken to indicate the ratio of the diameter of the surface area ofthe largest side of a segment of material, treating or assuming suchsegment surface area to be circular, to the thickness of the material(on average). Accordingly, the platelets utilized in the invention willpossess an average aspect ratio of from about 10 to about 10,000,preferably 100 to 1000. Preferably, the platelets will be larger than 5microns in the shortest dimension, the dimensions of a platelet whichmay be used in the invention being, for example, 6 mm×2 mm×15 μm.

In a particularly advantageous aspect of the invention, particle size ofthe organic polymeric particulate matter may be managed or adjusted toadvance or retard the reaction or degradation of the gelled suspensionin the fracture. Thus, for example, of the total particulate mattercontent, 20 percent may comprise larger particles, e.g., greater than100 microns, and 80 percent smaller, say 80 percent smaller than 20micron particles. Such blending in the gelled suspension may provide,because of surface area considerations, a different time of completionof reaction or decomposition of the particulate matter, and hence thetime of completion of gel decomposition or breaking, when compared withthat provided by a different particle size distribution.

The selection of the fluid or liquid to form the suspension with thesolid organic polymeric particulate material and other components, suchas gellant and proppant, is largely a matter of choice, within thecapability of those skilled in the art, and per se forms no part of thepresent invention. As such persons will be aware, however, the fluid,particulate material, gel forming material, etc., must be sufficientlycompatible to the extent that they do not react with one another at arate which would deleteriously interfere to any significant extent withthe intended functions specified herein. Commonly, the particular fluidchosen will be determined by such considerations as treatingtemperature, concentration of solid material to be carried, and thedesired objective. In general, any suitable fluid or liquid whichprovides sufficient viscosity, perhaps in conjunction with solid fibrousmaterials therein, to transport the proppant and other componentsutilized to the fracturing area or fracture, does not unduly interferewith the effectiveness of the solid particulate matter of the invention,and which results in minimal damage to the pack and to the formation,may be used, it being understood that the term “fluid”, includesmixtures of such materials. The fluid will preferably be aqueous, andmay comprise a gas, i.e., a foam may be employed. Any common aqueouswell treatment fluid may be employed, keeping the requirementspreviously mentioned in mind. Suitable fluids may also include aqueoussolutions of viscoelastic surfactants, i.e., surfactants which arecapable of providing viscosity without requiring the addition ofpolymers. Fluids comprising oil-in-water emulsions may be used, and, inthe appropriate instance, hydrocarbon fluids, such as diesel, may beused. Particularly preferred are the type of fracturing fluids describedby Nimerick, Crown, McConnell, and Ainley in U.S. Pat. No. 5,259,455,incorporated herein by reference, and those disclosed in U.S. Pat. No.4,686,052, incorporated herein by reference. Proportions of thecomponents of the fluid suspension are selected to insure that fluidcharacter, i.e., flowability, and suspension of the organic polymericparticulate material and solid material, e.g., proppant, are maintainedduring pumping or down well transport, i.e., an amount of the welltreatment fluid or liquid is provided or present sufficient to insurefluid flow for the suspensions. Generally, the composite fluids or fluidsuspensions of the invention will comprise viscous liquids.

The solid particulate matter, e.g., fibers, or fibers and/or platelet,containing fluid suspensions used in the invention may be prepared inany suitable manner or in any sequence or order. Thus, the suspensionmay be provided by blending in any order at the surface, and byaddition, in suitable proportions, of the components to the fluid orslurry during treatment on the fly. The suspensions may also be blendedoffsite. In the case of some materials, which are not readilydispersible, the fibers should be “wetted” with a suitable fluid, suchas water or a wellbore fluid, before or during mixing with thefracturing fluid, to allow better feeding of the fibers. Good mixingtechniques should be employed to avoid “clumping” of the particulatematter.

To the extent other breaker materials are employed, the total amount ofthe solid particulate matter of the invention may be reduced. It ispossible; however, to provide a combination of solid particulate matterin the manner of the invention along with minor amounts, i.e., less thanfifty percent, of other breaker materials, such combinations providingsignificant transport advantages if the solid particulate matter is inthe form of fibers or platelets. As will be understood by those skilledin the art, in the case where fibers and/or platelets are employed toform a porous pack upon completion of the fracturing operation orprocedure, e.g., as described in the procedures of the aforementionedU.S. Pat. No. 5,439,055, incorporated herein by reference; U.S. Pat. No.5,330,005, incorporated herein by reference; and U.S. Pat. No.5,501,275, incorporated herein by reference, the total amount of fibersemployed or pumped, assuming the use of suitable fibers as the solidorganic polymeric particulate matter, will include that required for gelbreaking and that for porous pack formation. As those skilled in the artwill recognize, the fibers employed for pack strengthening will bechosen for durability rather than for the characteristics desired in thebreaker materials selected herein, so that, in a given fracturingoperation, both types of fibers may be utilized, each contributing adesigned function and both contributing to or enhancing matter mobilityor transport. Concentrations of “pack-forming” fibers and/or plateletsin the fracturing fluid suspension for porous pack formation will bethose described in the above listed patents, with even quite minoramounts of fibers and/or platelets being effective or sufficient toenhance transport.

Any suitable polymeric gel forming material or gellant, preferably watersoluble, used by those skilled in the art to treat subterraneanformations and form stable or stabilized gels of the fluid suspensionmay be employed in the invention. For simplicity hereinafter, includedin the phrase “water soluble”, as applied to the gellant, are thosesuitable polymeric materials which are dispersible or suspendable inwater or aqueous liquid. Suitable gellants also include crosslinkablepolymers or monomers for forming such polymers under the conditionsextant. Such cross-linkable polymeric and polymer forming materials arewell known, and the crosslinked polymer or polymers which produce thestable or stabilized gel are preferably formed by reacting or contactingappropriate proportions of the crosslinkable polymer with a crosslinkingagent or agents. Similarly, procedures for preparing gelablecompositions or fluids and conditions under which such compositions formstable gels in subterranean formations are well known to those skilledin the art. As indicated, gel-forming compositions according to theinvention may be formed by mixing, in water, the water solublecrosslinkable polymer and the crosslinking agent.

In forming the gel, the crosslinkable polymer(s) and crosslinking agentand concentrations thereof are normally selected to assure (a) gelformation or presence at subterranean (i.e., formation or reservoir)conditions and (b) suitable time allotment for injection of thecomposition prior to the completion of gelation, or sufficient fluidityof the gelled composition to allow pumping down well. The polymer (ormonomers used to form the polymer) and the crosslinking agent aregenerally selected and supplied in amounts effective to achieve theseobjectives. By “effective” amounts of the polymer or polymers (ormonomers) and crosslinking agents is meant amounts sufficient to providecrosslinked polymers and form the desired stable gel under theconditions extant. Generally, a water soluble crosslinkable polymerconcentration in the aqueous liquid of from about 0.05 to about 40percent, preferably from about 0.1 percent to about 10 percent, and,most preferably, from about 0.2 percent to about 7 percent, may beemployed (or sufficient monomer(s) to form these amounts of polymer).Typically, the crosslinking agent is employed in the aqueous liquid in aconcentration of from about 0.001 percent to about 2 percent, preferablyfrom about 0.005 percent to about 1.5 percent, and, most preferably,from about 0.01 percent to about 1.0 percent.

However, if a crosslinked polymer is to be used, the fluids of theinvention need not contain both the crosslinkable polymer and thecrosslinking agent at the surface. The crosslinkable polymer or thecrosslinking agent may be omitted from the fluid sent downhole, theomitted material being introduced into the subterranean formation as aseparate slug, either before, after, or simultaneously with theintroduction of the fluid. In such cases, concentrations of the slugswill be adjusted to insure the required ratios of the components forproper gel formation at the desired location. Preferably, the surfaceformulated composition or fluid comprises at least the crosslinkablepolymeric material (e.g., acrylamide, vinyl acetate, acrylic acid, vinylalcohol, methacrylamide, ethylene oxide, or propylene oxide). Morepreferably, the composition comprises both (a) the crosslinking agentand (b) either (i) the crosslinkable polymer or (ii) the polymerizablemonomers capable of forming a crosslinkable polymer. In treating asubterranean fracture, the formulations may be allowed to gel or begingelation before entering the formation.

As indicated, mixtures of polymeric gel forming material or gellants maybe used. Materials which may be used include water soluble crosslinkablepolymers, copolymers, and terpolymers, such as polyvinyl polymers,polyacrylamides, cellulose ethers, polysaccharides, lignosulfonates,ammonium salts thereof, alkali metal salts thereof, alkaline earth saltsof lignosulfonates, and mixtures thereof. Specific polymers are acrylicacid-acrylamide copolymers, acrylic acid-methacrylamide copolymers,polyacrylamides, partially hydrolyzed polyacrylamides, partiallyhydrolyzed polymethacrylamides, polyvinyl alcohol, polyvinyl acetate,polyalkyleneoxides, carboxycelluloses, carboxyalkylhydroxyethylcelluloses, hydroxyethylcellulose, galactomannans (e.g., guar gum),substituted galactomannans (e.g., hydroxypropyl guar),heteropolysaccharides obtained by the fermentation of starch-derivedsugar (e.g., xanthan gum), ammonium and alkali metal salts thereof, andmixtures thereof. Preferred water soluble crosslinkable polymers includehydroxypropyl guar, carboxymethylhydroxypropyl guar, partiallyhydrolyzed polyacrylamides, xanthan gum, polyvinyl alcohol, the ammoniumand alkali metal salts thereof, and mixtures thereof.

Similarly, the crosslinking agent(s) may be selected from those organicand inorganic compounds well known to those skilled in the art usefulfor such purpose, and the phrase “crosslinking agent”, as used herein,includes mixtures of such compounds. Exemplary organic crosslinkingagents include, but are not limited to, aldehydes, dialdehydes, phenols,substituted phenols, ethers, and mixtures thereof. Phenol, resorcinol,catechol, phloroglucinol, gallic acid, pyrogallol, 4,4′-diphenol,1,3-dihydroxynaphthalene, 1,4-benzoquinone, hydroquinone, quinhydrone,tannin, phenyl acetate, phenyl benzoate, 1-naphthyl acetate, 2-naphthylacetate, phenyl chloracetate, hydroxyphenylalkanols, formaldehyde,paraformaldehyde, acetaldehyde, propanaldehyde, butyraldehyde,isobutyraldehyde, valeraldehyde, heptaldehyde, decanal, glyoxal,glutaraldehyde, terephthaldehyde, hexamethyl-enetetramine, trioxane,tetraoxane, polyoxymethylene, and divinylether may be used. Typicalinorganic crosslinking agents are polyvalent metals, chelated polyvalentmetals, and compounds capable of yielding polyvalent metals, includingorganometallic compounds as well as borates and boron complexes, andmixtures thereof. Preferred inorganic crosslinking agents includechromium salts, complexes, or chelates, such as chromium nitrate,chromium citrate, chromium acetate, chromium propionate, chromiummalonate, chromium lactate, etc.; aluminum salts, such as aluminumcitrate, aluminates, and aluminum complexes and chelates; titaniumsalts, complexes, and chelates; zirconium salts, complexes or chelates,such as zirconium lactate; and boron containing compounds such as boricacid, borates, and boron complexes. Fluids containing additives such asthose described in U.S. Pat. No. 4,683,068 and U.S. Pat. No. 5,082,579may be used.

As mentioned, the pre-gel fluid suspension formed in the invention maybe foamed, normally by use of a suitable gas. Foaming procedures arewell known, and per se form no part of the invention. In such instances,the fluids of the invention will preferably include a surfactant orsurfactants. Preferred surfactants are water-soluble or dispersible andhave sufficient foaming ability to enable the composition, whentraversed or agitated by a gas, to foam. The selection of a suitablesurface active agent or agents, is within the ability of those skilledin the art. Preferred surfactants are those which, when incorporatedinto water in a concentration of about 5 weight percent or less (basedon the total weight of water and surfactant), meet the test described inthe aforementioned U.S. Pat. No. 5,246,073, incorporated herein byreference.

Similarly, the precise nature of the proppant employed is not critical,the proppant being selected for the desired purpose, i.e., “propping”open a fracture, and those skilled in the art may readily select anappropriate wellbore particulate solid or solids for the desiredpurpose. The term “proppant” is understood to include mixtures, and mayinclude, for example, a mixture of different sized proppants, or agravel. Resin coated sand or ceramic proppant may be used. Particles orbeads of silica, sintered materials or minerals, such as sinteredbauxite, alumina, or corundum, may be used. Generally, the proppant willbe added or present in the fluid in a concentration of from 0.5 or 1lb./gallon to about 25 lbs/gallon, preferably from 1 lb./gallon to about20 lbs/gallon. Normally, the proppant will have an average particle sizeless than about 8 mesh and greater than 60 or 80 mesh (U.S.). Sizedmixtures of particles may be used, such as the common larger sizednatural and synthetic inorganic proppant mixtures. Sized sand andsynthetic inorganic proppants such as 20/40 sized sand, 16/20 sizedsand, 12/20 sized sand, 8/12 sized sand, and similarly sized ceramicproppants, such as “CARBOLITE™” proppants, may be used.

The novel blend of aqueous suspending fluid, proppant, gellant,crosslinking agent, and organic polymeric particulate matter may beprepared, as indicated, in any suitable manner, the components beingblended in any suitable sequence. Normally, however, the preferred jobexecution practice is to mix the entire batch to be pumped during thejob. In some instances, it may be preferred to pump the suspension ofthe invention only during a portion of the job, e.g., as the last 10-25%of the proppant into the fracture as a “tail-in”, to control flow backin the most economical manner or for other reasons. A slug may also bepumped at other stages. As mentioned, the invention has particularadvantage in treatment of subterranean formations having a temperatureabove about 225° F.

In one procedural aspect of the invention, the fluid suspension ispumped down well, normally gelled, through the wellbore under fracturingpressure to the subterranean formation, and the subterranean formationmay be fractured or the fracture may be extended. Gelling may beinitiated or enhanced, for example, by temperature or by pH control, ina manner known to those skilled in the art. The gelled suspension isdeposited in the formation, and after a suitable interval, such as afterthe fracturing operation is completed, the decomposition or reaction ofthe particulate matter in the downwell environment becomes significant.If necessary, the interval may be extended as appropriate to allow thegelled suspension to “break” or degrade. As used herein, the term“downwell environment” simply refers to the circumstances acting on theorganic polymeric particulate matter downwell, including, but notlimited to, the temperature of the subterranean formation, thecomposition of the formation, and any component or components of thesuspension. Upon degradation of the gel by the action of thedecomposition or reaction products, the fluids resulting from thebreaking of the gel, minus leak-off, are then returned or allowed toreturn from the deposit locus to the wellbore, the decomposition orreaction of the solid particulate matter in effect “removing” organicpolymeric particulate matter from the deposit. If additional particulatematter, such as durable fibers and/or platelets, or other materials arein the suspension deposited in the fracture, a matrix or pack of suchand proppant (with a minor residuum of welltreating fluid) is left inthe fracture.

Suitable choline compounds for use in this invention include, withoutlimitation, any choline salt. Exemplary examples include, withoutlimitation, choline halides, choline sulfate, choline sulfite, cholinephosphate, choline phosphite, choline carboxylates, or mixtures orcombinations thereof. Exemplary examples of choline halides includingcholine fluoride, choline chloride, choline bromide, choline iodide, ormixtures or combinations thereof. Exemplary examples of cholinecarboxylates including, without limitation, choline formate, cholinecitrate, choline salicylate, choline propanate, similar cholinecarboxylates or mixtures or combinations thereof.

Suitable amines for use in the clay control compositions of thisinvention include, without limitation, di- and tri-alkyl substitutedamines and mixtures or combinations thereof, where the alkyl groupsinclude from 3 to 20 carbon atoms and/or hetero atoms. In certainembodiments, the clay control compounds can also include di-alkylsulfides and di- and tri-alkyl phosphines where the alkyl groups includefrom 3 to 20 carbon atoms and/or hetero atoms.

Suitable ammonium salts for use in the clay control compositions of thisinvention include, without limitation, three general types of cationicmaterials: single-site cationic ammonium compounds, oligocationicammonium compounds, and polycationic ammonium compounds and mixtures orcombinations thereof. In certain embodiments, the clay control compoundcan also include phosphonium compounds and sulfonium compounds andmixtures or combinations thereof. Together the ammonium, phosphonium,and sulfonium compounds are sometimes referred to herein as “cationicformation control additives.”

The single site amine and quaternaries useful as cationic formationcontrol additives in my invention include di-, tri, and tetra-alkylsubstituted amine and ammonium compounds wherein the alkyl groupsinclude from 3 to 8 carbon atoms (Brown U.S. Pat. No. 2,761,835,incorporated herein by reference); substituted pyridine, pyridinium,morpholine and morphilinium compounds having from 1 to 6 carbon atoms inone or more substituent groups (Brown U.S. Pat. No. 2,761,840,incorporated herein by reference), additional heterocyclic nitrogencompounds such as histamine, imidazoles and substituted imidazoles,piperazines, piperidines, vinyl pyridines, and the like as described inBrown U.S. Pat. No. 2,761,836, incorporated herein by reference, thetrialkylphenylammonium halides, dialkylmorpholinium halides andepihalohydrin derivatives described by Himes et al in the U.S. Pat. No.4,842,073, incorporated herein by reference, and the allyl ammoniumcompounds of the formula (CH₂═—CHCH₂)_(n)N⁺(CH₃)_(4-n)X⁻; where X⁻ isany anion which does not adversely react with the formation or thetreatment fluid, described by Thomas and Smith in U.S. Pat. No.5,211,239, incorporated herein by reference. In certain embodiments, thesingle site quaternaries are diallyl dimethyl ammonium chloride (DADMAC)(that is, the above formula where n=2 and X^(−;) is Cl^(−;)), andtetramethyl ammonium chloride, sometimes referred to as TMAC.

Oligocationics useful as cationic formation control additives in myinvention include di- and polyamines (up to 100 nitrogens) substitutedwith alkyl groups having up to 12 carbon atoms (one or more of thenitrogens may be quaternized) as described by Brown in U.S. Pat. No.2,761,843, incorporated herein by reference, and polyquaternariesdescribed by Krieg in U.S. Pat. No. 3,349,032, incorporated herein byreference, namely alkyl aryl, and alkaryl bis- and polyquaternarieswherein two quaternary ammonium nitrogens are connected by variousconnecting groups having from 2-10 carbon atoms. In certain embodiments,the poly site quanternaries are polyDADMAC reagents as described in U.S.Pat. No. 6,921,742 to Smith, incorporated herein by reference.

Polyquaternary (cationic) formation control additives useful in myinvention include those described by McLaughlin in the U.S. Pat. Nos.4,366,071 and 4,374,739, incorporated herein by reference, namelypolymers containing repeating groups having pendant quaternary nitrogenatoms wherein the quaternizing moieties are usually alkyl groups butwhich can include other groups capable of combining with the nitrogenand resulting in the quaternized state. I may also use any of thenumerous polymers including quaternized nitrogen atoms which areintegral to the polymer backbone, and other polymers having repeatingquaternized units, as described in U.S. Pat. No. 4,447,342.Nitrogen-based cationic moieties may be interspersed with and/orcopolymerized with up to 65% by weight (in certain embodiments, 1% to65% by weight) nonionics such as acrylamide and even some anionics suchas acrylic acid or hydrolyzed acrylamide. Molecular weights of thepolymers may be quite high-up to a million or more. Such copolymers areincluded in my definition of polycationic formation control additivesuseful in my invention.

In certain embodiments, the anions for association with the quaternizednitrogen atoms are halide anions, such as chloride ions, that readilydissociate in the aqueous drilling or other formation treatment fluid,but any anions, including formate anions, may be used which will notinterfere with the purposes of the formation treatment. Persons skilledin the art may wish to review the various anions mentioned in the aboveincorporated patents.

Thus, it is seen that a cationic formation control additive useful in myinvention is a material having from one to hundreds or thousands ofcationic sites, generally either amines or quaternized amines, but mayinclude other cationic or quaternized sites such as phosphonium orsulfonium groups.

In the present invention, the inventor employs a choline compound and anamine, phosphine or sulfide and/or a cationic formation control additivewith or without a formate salt such as potassium formate. The cholinecompound and the formate compound may be added to the formation treatingor drilling fluid before or after the amine, phosphine or sulfide and/orcationic formation control additive. The potassium formate may be addedto the formation treating or drilling fluid before or after the cationicformation control additive, or may be made in situ by the reaction ofpotassium hydroxide and formic acid. The potassium hydroxide and formicacid may be added in any order, separately or together, before or afterthe addition of the cationic formation control additive, and need not beadded in exact molar proportions. Any effective amount of thecombination of a choline compound and formation control additives(amines, phosphines, or sulfides and/or cationic formation controladditives) may be used, but in certain embodiments, the ratios of acholine compound to formation control additive with or without potassiumformate of 25:75 to 75:25 by weight in the solution, in combinedconcentrations of at least 0.001% by weight in the drilling or otherformation treatment fluid. In certain embodiments, the additive packageto the fluid is between about 0.05 wt. % and about 5 wt. %.

EXPERIMENTS OF THE INVENTION Examples 1-9

The following clay control compositions were tested using clay packtesting and the measured CST value. Each example was run using the sametest procedure and the resulting tests values and other physicalproperties of certain formulations are tabulated in TABLES I-X.

The general formulation preparation process follows. The clay controladditive at the indicated weight percent was added to 250 mL ofDI-water. 30 g of clay pack were added and mixed for 5 minutes. The claypack comprises 17 wt. % Bentonite and 83 wt. % Silica Flower. After themix time, the resulting slurry was allowed to hydrate for 15 minutes.The resulting hydrated slurry was then remixed and the CST test was run.After 20 minutes hydration, the hydrated slurry was remixed and the claypack test was conducted.

TABLE I 10% NCL-100 and 90% Choline Chloride Time (min) Loading 0 1 3 510 Total CST 0.5 gpt   1 5 8 11 16 39 mL@1 Hr 223.6 1 gpt 5 12 15 20 3056 mL@1 Hr 121.9 2 gpt 8 23 43 49 75 182 mL@1 Hr  14.1

TABLE II 10% NCL-100 and 90% Choline Chloride Physical PropertiesPhysical Property Value pH 8.46 Specific Gravity @25 C. 1.084 % Water37.16 Appearance Clear to yellow liquid Density 8.917-9.084 % Water35-40

TABLE III Choline chloride Time (min) Loading 0 1 3 5 10 Total CST 1 gpt0 5 10 14 20  48 mL@1 Hr 150.5 2 gpt 8 25 43 50 70 165 mL@1 Hr 28.3 3gpt 9 40 60 60 88  250 mL@47 min 23.7

TABLE IV NCL-100 Time (min) Loading 0 1 3 5 10 Total CST 1 gpt 0 3 5 712 38 mL@1 Hr 196.5 2 gpt 5 7 12 15 22 57 mL@1 Hr 138.4 3 gpt 53 8 18 3045 69 mL@1 Hr 64.8

TABLE V Choline Formate Time (min) Loading 0 1 3 5 10 Total CST 1 gpt 03 7 10 15 40 mL@1 Hr 223.3 2 gpt 4 8 12 13 19 50 mL@1 Hr 104.7

TABLE VI Choline Citrate Time (min) Loading 0 1 3 5 10 Total CST 1 gptN/A N/A N/A N/A N/A N/A 340.5 2 gpt 0 3 5 7 10 31 mL@1 Hr 293.5

TABLE VII Choline Borate Time (min) Loading 0 1 3 5 10 Total CST 1 gptN/A N/A N/A N/A N/A N/A 348.1 2 gpt 0 2 4 6 10 30 mL@1 Hr 334.3

TABLE VIII 5% Alpha 1505 (Benzyl quaternary Ammonium Chloride) 95%Choline Chloride Time (min) Loading 0 1 3 5 10 Total CST 0.5 gpt   0 3 56 10 25 mL@1 Hr 275.5 1 gpt 3 5 10 12 14 30 mL@1 Hr 210.1 2 gpt 10 32 4454 72 160 mL@1 Hr  22.8

TABLE IX 5% NCL-100 + 95% Choline Chloride Loading CST 0.5 gpt 243.4   1gpt 143.5   2 gpt 17.5

TABLE X 20% NCL-100 + 80% Choline Chloride Loading CST 0.5 gpt 225.3   1gpt 149.2   2 gpt 25.1

CONCLUSION

The data shows that a blend of choline chloride and other current claycontrol additives produced a clay control additive having increasedperformance at lower concentrations as measured by Zeta potential andclay pack testing as shown in FIG. 1 and FIG. 2.

All references cited herein are incorporated by reference. Although theinvention has been disclosed with reference to its preferredembodiments, from reading this description those of skill in the art mayappreciate changes and modification that may be made which do not departfrom the scope and spirit of the invention as described above andclaimed hereafter.

I claim:
 1. A method for controlling clay swelling comprising the stepof: drilling a well through a formation including swellable clay with anaqueous drilling fluid consisting essentially of a choline compound anda formation control additive, where the formation control additivesincluding an amine, a cationic formation control additive, or mixturesand combinations thereof.
 2. The method of claim 1, wherein the cholinecompound is selected from the group consisting of an alkali salt ofcholine, a carboxyate salt of choline, choline sulfate, choline sulfite,choline phosphate, choline phosphite, amine borate, and mixtures orcombinations thereof.
 3. The method of claim 1, wherein the cholinecompound is selected from the group consisting of choline fluoride,choline chloride, choline bromide, choline iodide, and mixtures orcombinations thereof.
 4. The method of claim 1, wherein the cholinecompound comprises choline chloride.
 5. The method of claim 1, whereinthe amine is selected from the group consisting of di-tri-alkylsubstituted amines, tri-alkyl substituted amines, and mixtures orcombinations thereof, where the alkyl groups include from 3 to 20 carbonatoms and/or hetero atoms.
 6. The method of claim 1, wherein thecationic formation control additive is selected from the groupconsisting of single-site cationic ammonium compounds, oligocationicammonium compounds, polycationic ammonium compounds, and mixtures orcombinations thereof.
 7. The method of claim 1, wherein the cationicformation control additive comprises tetramethylammonium chloride. 8.The method of claim 1, wherein the cationic formation control additivecomprises a homopolymer of dimethyl diallyl ammonium chloride.
 9. Themethod of claim 1, wherein the cationic formation control additivecomprises a copolymer of dimethyl diallyl ammonium chloride and about 1%to about 65% by weight acrylic acid or hydrolyzed acrylamide.
 10. Themethod of claim 1, further comprising potassium formate.
 11. The methodof claim 1, wherein a ratio of choline compound to formation controladditive is from about 75:25 to about 25:75.
 12. The method of claim 1,wherein a combined concentration of the formation control additive andthe choline compound is at least 0.001% by weight of the well drillingfluid.
 13. The method of claim 1, wherein the choline compound acarboxyate salt of choline.
 14. A method for controlling clay swellingcomprising the step of: drilling a well with a first drilling fluid, andadding a clay control composition consisting essentially of a cholinecompound and a formation control additive to the drilling fluid when thedrilling fluid is in contact with a formation including swellable clay,where the formation control additives including an amine, a cationicformation control additive, or mixtures and combinations thereof. 15.The method of claim 14, wherein the choline compound is selected fromthe group consisting of an alkali salt of choline, a carboxyate salt ofcholine, choline sulfate, choline sulfite, choline phosphate, cholinephosphite, amine borate, and mixtures or combinations thereof.
 16. Themethod of claim 14, wherein the choline compound is selected from thegroup consisting of choline fluoride, choline chloride, choline bromide,choline iodide, and mixtures or combinations thereof.
 17. The method ofclaim 14, wherein the choline compound comprises choline chloride. 18.The method of claim 14, wherein the amine is selected from the groupconsisting of di-tri-alkyl substituted amines, tri-alkyl substitutedamines, and mixtures or combinations thereof, where the alkyl groupsinclude from 3 to 20 carbon atoms and/or hetero atoms.
 19. The method ofclaim 14, wherein the cationic formation control additive is selectedfrom the group consisting of single-site cationic ammonium compounds,oligocationic ammonium compounds, polycationic ammonium compounds, andmixtures or combinations thereof.
 20. The method of claim 14, whereinthe cationic formation control additive comprises tetramethylammoniumchloride.
 21. The method of claim 14, wherein the cationic formationcontrol additive comprises a homopolymer of dimethyl diallyl ammoniumchloride.
 22. The method of claim 14, wherein the cationic formationcontrol additive comprises a copolymer of dimethyl diallyl ammoniumchloride and about 1% to about 65% by weight acrylic acid or hydrolyzedacrylamide.
 23. The method of claim 14, further comprising potassiumformate.
 24. The method of claim 14, wherein a ratio of choline compoundto formation control additive is from about 75:25 to about 25:75. 25.The method of claim 14, wherein a combined concentration of theformation control additive and the choline compound is at least 0.001%by weight of the well drilling fluid.
 26. The method of claim 14,wherein the choline compound a carboxyate salt of choline.